10-K

 

2015

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☑     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

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

EXXON MOBIL CORPORATION

(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 (4,152,756,609 shares outstanding at January 31, 2016)	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   ☑     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   ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ☑     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 submitted 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 post such files).    Yes   ☑     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 best of 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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer   ☑              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   ☑

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $83.20 on the New York Stock Exchange composite tape, was in excess of $346 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2016 Annual Meeting of Shareholders (Part III)

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015

TABLE OF CONTENTS

PART I
Item 1.	Business	1
Item 1A.	Risk Factors	2
Item 1B.	Unresolved Staff Comments	4
Item 2.	Properties	5
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]		27
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	31
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	32
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	32
Item 13.	Certain Relationships and Related Transactions, and Director Independence	33
Item 14.	Principal Accounting Fees and Services	33
PART IV
Item 15.	Exhibits, Financial Statement Schedules	33
Financial Section		34
Signatures		115
Index to Exhibits		117
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges
Exhibits 31 and 32 — Certifications

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 market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. Affiliates of ExxonMobil conduct extensive research programs in 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. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms like Corporation, Company, our, we  and its, 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, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2015 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.6 billion, of which $3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to decrease to approximately $5 billion in 2016 and 2017, mainly reflecting lower project activity in Canada. Capital expenditures are expected to account for approximately 30 percent of the total.

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

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Quarterly Information”, “Note 18: Disclosures about Segments and Related Information” and “Operating Summary”. Information on oil and gas reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section 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 meet the needs identified in each of our business segments. Information on Company‑sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2015. For technology licensed to third parties, revenues totaled approximately $158 million in 2015. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

The number of regular employees was 73.5 thousand, 75.3 thousand, and 75.0 thousand at years ended 2015, 2014 and 2013, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company‑operated retail sites (CORS). The number of CORS employees was 2.1 thousand, 8.4 thousand, and 9.8 thousand at years ended 2015, 2014 and 2013, respectively. The decrease in CORS employees reflects the multi‑year transition of the company‑operated retail network in portions of Europe to a more capital‑efficient Branded Wholesaler model.  

Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be found in “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-K and 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 website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, 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 these risk factors are not within the Company’s control and could adversely affect our business, our financial and operating results, or our financial condition. These risk factors include:

Supply and Demand

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas, and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical, and product prices and margins in turn depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Any material decline in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Upstream segment, financial condition and proved reserves. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Downstream and Chemical segments.

Economic conditions. The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government austerity programs, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to credit or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and other events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our 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, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of government subsidies or mandates; and changes in technology or consumer preferences that alter fuel choices, such as toward alternative fueled or electric vehicles.

Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change can also alter the relative costs 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, currency 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 altogether. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less 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. ExxonMobil is subject to laws and sanctions imposed by the U.S. or by other jurisdictions where we do business that may prohibit ExxonMobil or certain of its affiliates from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to competitors who may not be subject to 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 frameworks for oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government officials, and 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 in an 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 changes in 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);

· price controls;

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

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

· adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information, or 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 unilaterally, or 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 unpredictable 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 local 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 considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

Government sponsorship of alternative energy. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the Global Climate and Energy Project at Stanford University and research into liquid products from algae and biomass that can be further converted to transportation 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 business 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 are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we 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 exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources on line as scheduled and within budget.

Project management. The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime; and 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 government payment transparency reports.

Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements, regular reappraisal of our asset portfolio, and 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 need for continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful and able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions.

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

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our facilities are designed, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of engineering uncertainties, including those associated with wave, wind, and current intensity, marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rain fall events, and earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our robust facility engineering as well as our rigorous disaster preparedness and response and 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 report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs, and business plans could 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 2015

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. When crude oil and natural gas prices are in the range seen in early 2016 for an extended period of time, under the Securities and Exchange Commission’s (SEC) definition of proved reserves, certain quantities of oil and natural gas could temporarily not qualify as proved reserves. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. Otherwise, no major discovery or other favorable or adverse event has occurred since December 31, 2015, that would cause a significant change in the estimated proved reserves as of that date.

					Crude	Natural Gas		Synthetic	Natural	Oil-Equivalent
					Oil	Liquids	Bitumen	Oil	Gas	Basis
					(million bbls)	(million bbls)	(million bbls)	(million bbls)	(billion cubic ft)	(million bbls)
Proved Reserves
	Developed
		Consolidated Subsidiaries
			United States		1,155	272	-	-	13,353	3,652
			Canada/South America (1)		92	9	4,108	581	552	4,882
			Europe		158	34	-	-	1,593	458
			Africa		738	162	-	-	750	1,025
			Asia		1,586	121	-	-	4,917	2,526
			Australia/Oceania		73	34	-	-	1,962	434
				Total Consolidated	3,802	632	4,108	581	23,127	12,977
		Equity Companies
			United States		221	7	-	-	156	254
			Europe		25	-	-	-	6,146	1,049
			Asia		802	349	-	-	15,233	3,690
				Total Equity Company	1,048	356	-	-	21,535	4,993
				Total Developed	4,850	988	4,108	581	44,662	17,970
	Undeveloped
		Consolidated Subsidiaries
			United States		1,223	396	-	-	6,027	2,624
			Canada/South America (1)		168	6	452	-	575	722
			Europe		26	8	-	-	363	95
			Africa		225	5	-	-	43	237
			Asia		1,239	-	-	-	412	1,308
			Australia/Oceania		52	31	-	-	5,079	929
				Total Consolidated	2,933	446	452	-	12,499	5,915
		Equity Companies
			United States		33	6	-	-	64	50
			Europe		-	-	-	-	1,757	293
			Asia		275	52	-	-	1,228	531
				Total Equity Company	308	58	-	-	3,049	874
				Total Undeveloped	3,241	504	452	-	15,548	6,789
Total Proved Reserves					8,091	1,492	4,560	581	60,210	24,759

(1)   South America includes proved developed reserves of 0.1 million barrels of crude oil and natural gas liquids and 23 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 operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

B. Technologies Used in Establishing Proved Reserves Additions in 2015

Additions to ExxonMobil’s proved reserves in 2015 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 3-D and 4-D seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation 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 quality of 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 responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude and natural gas liquids, bitumen, synthetic oil and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The Manager of the Global Reserves group has 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 Society of Petroleum Engineers (SPE) and previously served on the SPE Oil and Gas Reserves Committee. The group is staffed with individuals that have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes individuals who hold advanced degrees in either Engineering or Geology. Several members of the group hold professional registrations in their field of expertise, and a member currently serves on the SPE Oil and Gas Reserves Committee.

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

2. Proved Undeveloped Reserves

At year-end 2015, approximately 6.8 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 27 percent of the 24.8 GOEB reported in proved reserves. This compares to the 8.8 GOEB of proved undeveloped reserves reported at the end of 2014. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 2.7 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to Kearl Expansion project start-up and drilling activity in the United States. Mainly due to low prices during 2015, the Corporation reclassified approximately 1 GOEB of proved undeveloped reserves, primarily natural gas reserves in the United States, which no longer meet the SEC definition of proved reserves.

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Development projects typically take two to four years from the time of recording proved undeveloped reserves to the start of production. However, the development time for large and complex projects can exceed five years. During 2015, extensions and purchases primarily related to United States unconventional and Abu Dhabi drilling added approximately 1.7 GOEB of proved undeveloped reserves. Overall, investments of $19.4 billion were made by the Corporation during 2015 to progress the development of reported proved undeveloped reserves, including $17 billion for oil and gas producing activities and an additional $2.4 billion for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 76 percent of the $25.4 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Australia, the United States, Kazakhstan, the Netherlands, Qatar, and Nigeria have remained undeveloped 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 required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals, and significant changes in long-term oil and natural gas price levels. Of the proved undeveloped reserves that have been reported for five or more years, 84 percent are contained in the aforementioned countries. The largest of these is related to LNG/Gas projects in Australia, where construction of the Gorgon LNG project is under way. In Kazakhstan, the proved undeveloped reserves are related to the remainder of the initial development of the offshore Kashagan field which is included in the North Caspian Production Sharing Agreement and the Tengizchevroil joint venture which includes a production license in the Tengiz – Korolev field complex. The Tengizchevroil joint venture is producing, and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. In the Netherlands, the Groningen gas field has proved undeveloped reserves related to installation of future stages of compression. These reserves will move to proved developed when the additional stages of compression are installed to maintain field delivery pressure.

7

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.

				2015		2014		2013
				(thousands of barrels daily)
Crude oil and natural gas liquids production				Crude Oil	NGL	Crude Oil	NGL	Crude Oil	NGL
	Consolidated Subsidiaries
		United States		326	86	304	85	283	85
		Canada/South America		47	8	52	9	57	10
		Europe		173	28	151	28	157	27
		Africa		511	18	469	20	451	18
		Asia		346	29	293	26	313	30
		Australia/Oceania		33	17	39	20	29	19
			Total Consolidated Subsidiaries	1,436	186	1,308	188	1,290	189
	Equity Companies
		United States		61	3	63	2	61	2
		Europe		3	-	5	-	6	-
		Asia		241	68	236	69	373	68
			Total Equity Companies	305	71	304	71	440	70
Total crude oil and natural gas liquids production				1,741	257	1,612	259	1,730	259
Bitumen production
	Consolidated Subsidiaries
		Canada/South America		289		180		148
Synthetic oil production
	Consolidated Subsidiaries
		Canada/South America		58		60		65
Total liquids production				2,345		2,111		2,202
				(millions of cubic feet daily)
Natural gas production available for sale
	Consolidated Subsidiaries
		United States		3,116		3,374		3,530
		Canada/South America (1)		261		310		354
		Europe		1,110		1,226		1,294
		Africa		5		4		6
		Asia		1,080		1,067		1,180
		Australia/Oceania		677		512		351
			Total Consolidated Subsidiaries	6,249		6,493		6,715
	Equity Companies
		United States		31		30		15
		Europe		1,176		1,590		1,957
		Asia		3,059		3,032		3,149
			Total Equity Companies	4,266		4,652		5,121
Total natural gas production available for sale				10,515		11,145		11,836
				(thousands of oil-equivalent barrels daily)
Oil-equivalent production				4,097		3,969		4,175

(1)   South America includes natural gas production available for sale for 2015, 2014 and 2013 of 21 million, 21 million, and 28 million cubic feet daily, respectively.

8

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		Total
During 2015				(dollars per unit)
	Consolidated Subsidiaries
		Average production prices
			Crude oil, per barrel	41.87		44.30	49.04	51.01	48.30		49.56	47.75
			NGL, per barrel	16.96		21.91	27.50	33.41	21.14		29.75	22.16
			Natural gas, per thousand cubic feet	1.65		1.78	6.47	1.57	2.02		5.13	2.95
			Bitumen, per barrel	-		25.07	-	-	-		-	25.07
			Synthetic oil, per barrel	-		48.15	-	-	-		-	48.15
		Average production costs, per oil-equivalent barrel - total		12.50		22.68	15.86	10.31	7.71		8.86	12.97
		Average production costs, per barrel - bitumen		-		19.20	-	-	-		-	19.20
		Average production costs, per barrel - synthetic oil		-		41.83	-	-	-		-	41.83
	Equity Companies
		Average production prices
			Crude oil, per barrel	46.34		-	46.05	-	48.44		-	47.99
			NGL, per barrel	15.37		-	-	-	32.36		-	31.75
			Natural gas, per thousand cubic feet	2.05		-	6.27	-	5.83		-	5.92
		Average production costs, per oil-equivalent barrel - total		22.15		-	7.75	-	1.41		-	3.89
	Total
		Average production prices
			Crude oil, per barrel	42.58		44.30	48.97	51.01	48.36		49.56	47.79
			NGL, per barrel	16.92		21.91	27.50	33.41	28.94		29.75	24.77
			Natural gas, per thousand cubic feet	1.65		1.78	6.37	1.57	4.84		5.13	4.16
			Bitumen, per barrel	-		25.07	-	-	-		-	25.07
			Synthetic oil, per barrel	-		48.15	-	-	-		-	48.15
		Average production costs, per oil-equivalent barrel - total		13.16		22.68	13.09	10.31	3.96		8.86	10.56
		Average production costs, per barrel - bitumen		-		19.20	-	-	-		-	19.20
		Average production costs, per barrel - synthetic oil		-		41.83	-	-	-		-	41.83
During 2014
	Consolidated Subsidiaries
		Average production prices
			Crude oil, per barrel	84.00		86.46	96.43	97.46	95.27		95.56	93.21
			NGL, per barrel	39.70		51.86	53.68	65.21	40.81		56.77	47.07
			Natural gas, per thousand cubic feet	3.61		3.96	8.18	2.61	3.71		5.87	4.68
			Bitumen, per barrel	-		62.68	-	-	-		-	62.68
			Synthetic oil, per barrel	-		89.76	-	-	-		-	89.76
		Average production costs, per oil-equivalent barrel - total		13.35		33.03	22.29	12.58	8.64		11.05	15.94
		Average production costs, per barrel - bitumen		-		32.66	-	-	-		-	32.66
		Average production costs, per barrel - synthetic oil		-		55.32	-	-	-		-	55.32
	Equity Companies
		Average production prices
			Crude oil, per barrel	91.24		-	88.68	-	93.42		-	92.89
			NGL, per barrel	38.77		-	-	-	65.31		-	64.41
			Natural gas, per thousand cubic feet	4.54		-	8.28	-	10.00		-	9.38
		Average production costs, per oil-equivalent barrel - total		24.34		-	6.10	-	1.85		-	4.22
	Total
		Average production prices
			Crude oil, per barrel	85.23		86.46	96.17	97.46	94.44		95.56	93.15
			NGL, per barrel	39.68		51.86	53.68	65.21	58.52		56.77	51.84
			Natural gas, per thousand cubic feet	3.62		3.96	8.23	2.61	8.36		5.87	6.64
			Bitumen, per barrel	-		62.68	-	-	-		-	62.68
			Synthetic oil, per barrel	-		89.76	-	-	-		-	89.76
		Average production costs, per oil-equivalent barrel - total		14.10		33.03	15.59	12.58	4.44		11.05	12.55
		Average production costs, per barrel - bitumen		-		32.66	-	-	-		-	32.66
		Average production costs, per barrel - synthetic oil		-		55.32	-	-	-		-	55.32

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				United		Canada/				Australia/
				States	S. America		Europe	Africa	Asia		Oceania	Total
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	104.13
			NGL, per barrel	44.30		44.96	65.36	75.24	40.83		59.55	51.12
			Natural gas, per thousand cubic feet	2.99		2.80	10.07	2.79	4.10		4.20	4.60
			Bitumen, per barrel	-		59.63	-	-	-		-	59.63
			Synthetic oil, per barrel	-		93.96	-	-	-		-	93.96
		Average production costs, per oil-equivalent barrel - total		12.02		32.02	19.57	13.95	8.95		16.81	15.42
		Average production costs, per barrel - bitumen		-		34.30	-	-	-		-	34.30
		Average production costs, per barrel - synthetic oil		-		50.94	-	-	-		-	50.94
	Equity Companies
		Average production prices
			Crude oil, per barrel	102.24		-	99.26	-	103.96		-	103.66
			NGL, per barrel	42.02		-	-	-	70.90		-	69.96
			Natural gas, per thousand cubic feet	4.37		-	9.28	-	10.19		-	9.82
		Average production costs, per oil-equivalent barrel - total		22.77		-	3.79	-	1.87		-	3.36
	Total
		Average production prices
			Crude oil, per barrel	95.11		98.91	106.49	108.73	104.98		107.92	104.01
			NGL, per barrel	44.24		44.96	65.36	75.24	61.64		59.55	56.26
			Natural gas, per thousand cubic feet	3.00		2.80	9.59	2.79	8.53		4.20	6.86
			Bitumen, per barrel	-		59.63	-	-	-		-	59.63
			Synthetic oil, per barrel	-		93.96	-	-	-		-	93.96
		Average production costs, per oil-equivalent barrel - total		12.72		32.02	12.42	13.95	4.41		16.81	11.48
		Average production costs, per barrel - bitumen		-		34.30	-	-	-		-	34.30
		Average production costs, per barrel - synthetic oil		-		50.94	-	-	-		-	50.94

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of 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 reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial 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

				2015	2014	2013
Net Productive Exploratory Wells Drilled
	Consolidated Subsidiaries
		United States		-	3	8
		Canada/South America		1	3	4
		Europe		1	1	-
		Africa		1	2	2
		Asia		2	-	-
		Australia/Oceania		1	-	-
			Total Consolidated Subsidiaries	6	9	14
	Equity Companies
		United States		-	-	-
		Europe		1	2	1
		Asia		-	-	1
			Total Equity Companies	1	2	2
Total productive exploratory wells drilled				7	11	16
Net Dry Exploratory Wells Drilled
	Consolidated Subsidiaries
		United States		1	2	2
		Canada/South America		-	1	4
		Europe		2	1	1
		Africa		-	1	-
		Asia		-	-	-
		Australia/Oceania		-	-	-
			Total Consolidated Subsidiaries	3	5	7
	Equity Companies
		United States		1	2	1
		Europe		1	-	-
		Asia		-	-	-
			Total Equity Companies	2	2	1
Total dry exploratory wells drilled				5	7	8

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				2015	2014	2013
Net Productive Development Wells Drilled
	Consolidated Subsidiaries
		United States		692	721	755
		Canada/South America		53	178	201
		Europe		10	8	13
		Africa		23	41	33
		Asia		14	19	30
		Australia/Oceania		4	5	3
			Total Consolidated Subsidiaries	796	972	1,035
	Equity Companies
		United States		390	340	328
		Europe		1	2	2
		Asia		2	1	8
			Total Equity Companies	393	343	338
Total productive development wells drilled				1,189	1,315	1,373
Net Dry Development Wells Drilled
	Consolidated Subsidiaries
		United States		5	6	5
		Canada/South America		-	3	-
		Europe		3	1	2
		Africa		1	-	-
		Asia		-	-	-
		Australia/Oceania		-	-	-
			Total Consolidated Subsidiaries	9	10	7
	Equity Companies
		United States		-	-	-
		Europe		-	1	1
		Asia		-	-	-
			Total Equity Companies	-	1	1
Total dry development wells drilled				9	11	8
	Total number of net wells drilled			1,210	1,344	1,405

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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 crude 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 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2015, the company’s share of net production of synthetic crude oil was 58 thousand barrels per day and share of net acreage was 63 thousand acres in the Athabasca oil sands deposit.

Kearl Operations. Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering 49 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 from open-pit mining operations, and processed through bitumen extraction and froth treatment trains. The product, a blend of bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail. During 2015, average net production at Kearl was 149 thousand barrels per day. The Kearl Expansion project was completed and started up in 2015, adding additional capacity of 110 thousand barrels of bitumen per day.

5. Present Activities

A. Wells Drilling

				Year-End 2015		Year-End 2014
				Gross	Net	Gross	Net
Wells Drilling
	Consolidated Subsidiaries
		United States		860	379	1,120	442
		Canada/South America		15	10	35	29
		Europe		14	6	18	8
		Africa		23	7	33	12
		Asia		65	18	90	26
		Australia/Oceania		3	1	10	4
			Total Consolidated Subsidiaries	980	421	1,306	521
	Equity Companies
		United States		18	3	31	6
		Europe		9	3	4	1
		Asia		1	-	1	-
			Total Equity Companies	28	6	36	7
Total gross and net wells drilling				1,008	427	1,342	528

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2015 acreage holdings totaled 14.0 million net acres, of which 1.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During the year, 1,063.2 net exploration and development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico and the Bakken oil play in North Dakota and Montana. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia and the Utica Shale of Ohio.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2015 was 1.2 million acres. A total of 3.5net development wells were completed during the year. The deepwater Hadrian South project and the non-operated Lucius project started up in 2015. ExxonMobil continued development activities on the Heidelberg and Julia Phase 1 projects. Offshore California 1.0 net development well was completed.

13

Participation in Alaska production and development continued with a total of 20.9 net development wells completed. Development activities continued on the Point Thomson project.

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations:ExxonMobil’s year-end 2015 acreage holdings totaled 6.2 million net acres, of which 1.9 million net acres were offshore. A total of 11.1 net exploration and development wells were completed during the year. Development activities continued on the Hebron project during 2015.

In Situ Bitumen Operations:ExxonMobil’s year-end 2015 in situ bitumen acreage holdings totaled 0.7 million net onshore acres. A total of 41.0 net development wells were completed during the year. The Cold Lake Nabiye Expansion project started up in 2015.

Argentina

ExxonMobil’s net acreage totaled 0.9 million onshore acres at year-end 2015, and there were 1.0 net development wells completed during the year.

EUROPE

Germany

A total of 4.8 million net onshore acres were held by ExxonMobil at year-end 2015, with 0.7 net development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2015, of which 1.2 million acres were onshore. A total of 3.5 net exploration and development wells were completed during the year.

Norway

ExxonMobil’s net interest in licenses at year-end 2015 totaled approximately 0.2 million acres, all offshore. A total of 6.8 net exploration and development wells were completed in 2015. The non-operated Aasgard Subsea Compression project started up in 2015.   

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2015 totaled approximately 0.5 million acres, all offshore. A total of 5.1 net development wells were completed during the year.

AFRICA

Angola

ExxonMobil’s net acreage totaled 0.4 million offshore acres at year-end 2015, with 3.6 net development wells completed during the year. On Block 15, the Kizomba Satellites Phase 2 project started up in 2015. On Block 32, development activities continued on the Kaombo Split Hub project.

Chad

ExxonMobil’s net year-end 2015 acreage holdings consisted of 46 thousand onshore acres, with 15.6 net development wells completed during the year.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2015, with 2.3 net development wells completed during the year. In 2015, ExxonMobil acquired deepwater acreage in Block EG 06.  

Nigeria

ExxonMobil’s net acreage totaled 1.1 million offshore acres at year-end 2015, with 2.9 net exploration and development wells completed during the year. In 2015, ExxonMobil acquired deepwater acreage in Block OPL 247. The deepwater Erha North Phase 2 project started up, and development drilling continued on the deepwater Usan project in 2015.

14

ASIA

Azerbaijan

At year-end 2015, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.9 net development wells were completed during the year.

Indonesia

At year-end 2015, ExxonMobil had 0.5 million net acres, 0.4 million net acres offshore and 0.1 million net acres onshore, with 3.2 net development wells completed during the year. In 2015, acreage was relinquished in the North Sumatra and Arun fields. The Banyu Urip onshore central processing facility started up in 2015.

Iraq

At year-end 2015, ExxonMobil’s onshore acreage was 0.6 million net acres. West Qurna Phase 1 oil field rehabilitation activities continued during 2015 andacross the life of this project will include drilling of new wells, working over of existing wells, and optimization and debottlenecking of existing facilities. In the Kurdistan Region of Iraq, after operations were temporarily suspended due to security concerns in the region during 2014, ExxonMobil resumed its seismic program and exploration drilling in 2015, with 1.6 net exploration wells completed during the year. 

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2015. A total of 3.7 net development wells were completed during 2015. Following a brief production period in 2013, Kashagan operations were suspended due to a leak in the onshore section of the gas pipeline. Working with our partners, activities are under way to replace both the oil and gas pipelines.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.2 million net acres offshore at year-end 2015. During the year, a total of 4.0 net development wells were completed.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2015. ExxonMobil participated in 62.2 million tonnes per year gross liquefied natural gas capacity and 2.0 billion cubic 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 2015.

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2015 were 85 thousand acres, all offshore. A total of 1.5 net development wells were completed. The Arkutun-Dagi project started up, and development activities continued on the Odoptu Stage 2 project in 2015.

At year-end 2015, ExxonMobil’s net acreage in the Rosneft joint venture agreements for the Kara, Laptev, Chukchi and Black Seas was 63.6 million acres, all offshore. ExxonMobil and Rosneft formed a joint venture to evaluate the development of tight-oil reserves in western Siberia in 2013. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2015.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2015. During the year, a total of 3.6 net development wells were completed. Development activities continued on the Upper Zakum 750 project.

15

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2015 acreage holdings totaled 1.5 million net offshore acres. During the year, a total of 3.1 net exploration and development wells were completed. Construction activities continued on the Gas Conditioning Plant at Longford.

Project construction and commissioning activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2015. The project consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million tonnes per year LNG facility and a 280 million cubic feet per day 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 2015, with 1.5 net development wells completed during the year. The Papua New Guinea (PNG) LNG integrated development includes gas production and processing facilities in the southern PNG Highlands, onshore and offshore pipelines, and a 6.9 million tonnes per yearLNG facility near Port Moresby.

WORLDWIDE EXPLORATION

At year-end 2015, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 12.6 million net acres were held at year-end 2015 and 4.4net exploration wells were completed during the year in these countries.

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 delivery 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 natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 43 million barrels of oil and 2,800 billion cubic feet of natural gas for the period from 2016 through 2018. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves 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 2015				Year-End 2014
				Oil		Gas		Oil		Gas
				Gross	Net	Gross	Net	Gross	Net	Gross	Net
Gross and Net Productive Wells
	Consolidated Subsidiaries
		United States		20,662	8,334	33,657	20,307	18,424	7,939	33,149	20,398
		Canada/South America		5,045	4,741	4,559	1,769	5,012	4,659	4,577	1,782
		Europe		1,195	345	644	255	1,215	347	642	259
		Africa		1,315	517	20	8	1,299	513	19	8
		Asia		818	280	149	87	804	267	207	150
		Australia/Oceania		630	138	49	23	669	157	43	21
			Total Consolidated Subsidiaries	29,665	14,355	39,078	22,449	27,423	13,882	38,637	22,618
	Equity Companies
		United States		14,555	5,594	4,301	493	14,571	5,605	4,365	494
		Europe		13	6	570	180	57	20	567	179
		Asia		121	30	125	30	110	27	125	30
			Total Equity Companies	14,689	5,630	4,996	703	14,738	5,652	5,057	703
Total gross and net productive wells				44,354	19,985	44,074	23,152	42,161	19,534	43,694	23,321

There were 35,909 gross and 30,114 net operated wells at year-end 2015 and 35,446 gross and 29,870 net operated wells at year-end 2014. The number of wells with multiple completions was 1,266 gross in 2015 and 1,219 gross in 2014.

Note: Year-end 2014 consolidated subsidiaries well counts for gross and net wells in the United States were restated in regards to non-operated wells.

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B. Gross and Net Developed Acreage

				Year-End 2015		Year-End 2014
				Gross	Net	Gross	Net
				(thousands of acres)
Gross and Net Developed Acreage
	Consolidated Subsidiaries
		United States		14,827	9,327	14,777	9,367
		Canada/South America (1)		3,335	2,122	3,515	2,242
		Europe		3,275	1,473	3,337	1,506
		Africa		2,493	866	2,286	815
		Asia		1,934	562	1,817	551
		Australia/Oceania		2,123	781	2,123	758
			Total Consolidated Subsidiaries	27,987	15,131	27,855	15,239
	Equity Companies
		United States		939	209	949	208
		Europe		4,278	1,335	4,342	1,356
		Asia		628	155	628	156
			Total Equity Companies	5,845	1,699	5,919	1,720
Total gross and net developed acreage				33,832	16,830	33,774	16,959

(1)   Includes developed acreage in South America of 213 gross and 109 net thousands of acres for 2015 and 213 gross and 109 net thousands of acres for 2014.

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 2015		Year-End 2014
				Gross	Net	Gross	Net
				(thousands of acres)
Gross and Net Undeveloped Acreage
	Consolidated Subsidiaries
		United States		9,353	4,358	10,262	4,894
		Canada/South America (1)		19,328	10,113	16,100	12,250
		Europe		10,073	5,444	10,601	5,636
		Africa		10,586	5,306	22,143	15,020
		Asia		6,888	3,959	17,437	13,016
		Australia/Oceania		5,629	1,902	6,653	2,013
			Total Consolidated Subsidiaries	61,857	31,082	83,196	52,829
	Equity Companies
		United States		259	92	350	118
		Europe		-	-	-	-
		Asia		191,147	63,633	191,146	63,632
			Total Equity Companies	191,406	63,725	191,496	63,750
Total gross and net undeveloped acreage				253,263	94,807	274,692	116,579

(1)   Includes undeveloped acreage in South America of 10,634 gross and 4,970 net thousands of acres for 2015 and 9,056 gross and 8,083 net thousands of acres for 2014.

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

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D. Summary of Acreage Terms

UNITED STATES

Oil and gas exploration and production rights are acquired from mineral interest owners through a lease. Mineral interest owners include the Federal and State governments, as well as private mineral interest owners. Leases typically have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances regarding private property, a “fee interest” is 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 entitle the holder to continue existing licenses or leases upon completing specified work. In general, these license and lease agreements are held as long as there is production on the licenses and leases. Exploration licenses in offshore eastern Canada and the Beaufort Sea are held by work commitments of various 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 extension for continued production. Significant discovery licenses in the offshore, relating to currently undeveloped discoveries, do not have a definite term.

Argentina

The Federal Hydrocarbon Law was amended in December 2014. The onshore concession terms granted prior to the amendment are up to six years, divided into three potential exploration periods, with an optional extension for up to one year depending on the classification of the area. Pursuant to the amended law, the production term for a conventional production concession would be 25 years, and 35 years for an unconventional concession, with unlimited ten-year extensions possible, once a field has been developed.

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 each. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible 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 explicitly 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 conditions are 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. Onshore 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 to 45 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 explicitly 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 of the 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 for an 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 years, 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 period 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 of the 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 rounds 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 for a 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 continue in 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 regime 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 term of 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 at the 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 second 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 permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended up to 50 years at the discretion of the government.

Equatorial Guinea

Exploration, development and production activities are governed by production sharing contracts (PSCs) negotiated with the State Ministry of Mines, Industry and Energy. A new PSC was signed in 2015; the initial exploration period is five years for oil and gas, with multi-year extensions available at the discretion of the Ministry and limited relinquishments in the absence of commercial discoveries. The production period for crude oil ranges from 25 to 30 years, while the production period for natural gas ranges from 25 to 50 years.

Nigeria

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC typically holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase that can be divided into multiple optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end 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 offshore areas are valid for ten years, while in all other areas the licenses are for five years. Demonstrating a 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 onshore and 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 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. Commercial terms applicable to the existing joint venture oil production are defined by the Petroleum Profits Tax Act.

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

20

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 from 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 consists 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 years 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 contract (PSC), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. In 2012, Indonesia’s Constitutional Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but stated that all existing PSCs signed with BPMIGAS should remain in force until their expiry, and the functions and duties previously performed by BPMIGAS are to be carried out by the relevant Ministry of the Government of Indonesia until the promulgation of a new oil and gas law. By presidential decree, SKKMIGAS became the interim successor to BPMIGAS. The current PSCs have an exploration period of six years, which can be extended up to 10 years, 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 years and 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 acreage and 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 Ministry of 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 development and 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 for five 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 (PSCs) negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years, with extensions available as provided by the PSCs and at the discretion of the regional government of Kurdistan. The production period is 20 years with 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 with the 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. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

Malaysia

Production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The PSCs have terms ranging up to 29 years. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 29 years, depending on the provisions of the respective contract.

Qatar

The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic 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 1995. Due to force majeure events, the development period has been extended beyond its original expiration date by an additional 400 days, with the possibility of further extensions due to ongoing force majeure events.

21

Russia

Terms for ExxonMobil’s Sakhalin acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, 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, Laptev, Chukchi and Black Seas are governed by joint venture agreements concluded with Rosneft in 2013 and 2014 that cover certain of Rosneft’s offshore licenses. The Kara Sea licenses covered by the joint venture agreements concluded in 2013 extend through 2040 and include an exploration period through 2020. Additional licenses in the Kara, Laptev and Chukchi Seas covered by the joint venture agreements concluded in 2014 extend through 2043 and include an exploration period through 2023. The Kara, Laptev and Chukchi Sea licenses require development plan submission within eight years of a discovery and development activities within five years of plan approval. The Black Sea exploration license extends through 2017 and a discovery is the basis for obtaining a license for production. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.

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 time.

United Arab Emirates

An interest in the development and production activities of the Upper Zakum field, a major offshore field, 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 granted for 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 at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for the life of the field. Effective from July 1998, new production licenses are granted “indefinitely”. In each case, a production license may be terminated if no 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 with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license 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 extension of 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 viable at the time of application, but may become commercially viable within the maximum possible retention time of 15 years. Petroleum Retention licenses are 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 Petroleum 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 could become commercially viable in less than five years.

22

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 network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers around the world.

Refining Capacity At Year-End 2015 (1)

				ExxonMobil	ExxonMobil
				Share  KBD (2)	Interest %
United States
	Torrance		California	150	100
	Joliet		Illinois	236	100
	Baton Rouge		Louisiana	503	100
	Billings		Montana	60	100
	Baytown		Texas	561	100
	Beaumont		Texas	345	100
		Total United States		1,855
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	239	82.9
	Karlsruhe		Germany	78	25
	Augusta		Italy	198	100
	Trecate		Italy	132	74.8
	Rotterdam		Netherlands	191	100
	Slagen		Norway	116	100
	Fawley		United Kingdom	261	100
		Total Europe		1,655
Asia Pacific
	Altona		Australia	78	100
	Fujian		China	67	25
	Jurong/PAC		Singapore	592	100
	Sriracha		Thailand	167	66
		Total Asia Pacific		904
Middle East
	Yanbu		Saudi Arabia	200	50
Total Worldwide				5,035

(1)   Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. The listing excludes refineries owned through cost companies in Japan and New Zealand, and the Laffan Refinery in Qatar for which results are reported in the Upstream segment.

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

23

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

Retail Sites At Year-End 2015

United States
	Owned/leased		-
	Distributors/resellers		9,617
		Total United States	9,617
Canada
	Owned/leased		474
	Distributors/resellers		1,281
		Total Canada	1,755
Europe
	Owned/leased		2,438
	Distributors/resellers		3,612
		Total Europe	6,050
Asia Pacific
	Owned/leased		645
	Distributors/resellers		795
		Total Asia Pacific	1,440
Latin America
	Owned/leased		9
	Distributors/resellers		745
		Total Latin America	754
Middle East/Africa
	Owned/leased		372
	Distributors/resellers		263
		Total Middle East/Africa	635
Worldwide
	Owned/leased		3,938
	Distributors/resellers		16,313
		Total Worldwide	20,251

24

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 variety of other petrochemicals.

Chemical Complex Capacity At Year-End 2015 (1)(2)

								ExxonMobil
				Ethylene	Polyethylene	Polypropylene	Paraxylene	Interest %
North America
	Baton Rouge		Louisiana	1.0	1.3	0.4	-	100
	Baytown		Texas	2.2	-	0.7	0.7	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	1.0
Europe
	Antwerp		Belgium	-	0.4	-	-	100
	Fife		United Kingdom	0.4	-	-	-	50
	Gravenchon		France	0.4	0.4	0.3	-	100
	Meerhout		Belgium	-	0.5	-	-	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	0.3	0.2	0.2	0.2	25
	Singapore		Singapore	1.9	1.9	0.9	1.0	100
	Sriracha		Thailand	-	-	-	0.5	66
		Total Asia Pacific		2.2	2.1	1.1	1.7
Total Worldwide				9.0	8.6	2.7	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, capacity is ExxonMobil’s interest. The listing excludes cost company capacity in Japan.

25

Item 3.       Legal Proceedings

As reported in the Corporation’s Form 10-Q for the third quarter of 2015, following ExxonMobil Oil Corporation’s (EMOC) self-reporting of an air emission event at the ExxonMobil Beaumont Chemical Plant, the Texas Commission on Environmental Quality (TCEQ) notified EMOC on September 17, 2015, that it was seeking a penalty of $150,000 for exceeding provisions of the Texas Administrative Code and the Texas Health and Safety Code. On December 15, 2015, the TCEQ agreed with EMOC on the duration of the event, and the parties agreed to an administrative penalty of $50,000, of which $25,000 was paid to the TCEQ on January 7, 2016. The balance will be paid for a Supplemental Environmental Project upon endorsement by the TCEQ.

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

Item 4.       MINE SAFETY DISCLOSURES

Not applicable.

_______________________

26

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: 63
Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004, and was President through December 31, 2015. He became Chairman of the Board and Chief Executive Officer on January 1, 2006, positions he still holds as of the filing date.

Darren W. Woods	President
Held current title since:	January 1, 2016	Age: 51
Mr. Darren W. Woods was Vice President, Supply & Transportation, ExxonMobil Refining & Supply Company July 1, 2010 – July 31, 2012. He was President of ExxonMobil Refining & Supply Company August 1, 2012 – July 31, 2014 and Vice President of Exxon Mobil Corporation August 1, 2012 – May 31, 2014. He was Senior Vice President of Exxon Mobil Corporation June 1, 2014 – December 31, 2015. He became a Director and President of Exxon Mobil Corporation on January 1, 2016, positions he still holds as of this filing date.

Mark W. Albers	Senior Vice President
Held current title since:	April 1, 2007	Age: 59
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: 62
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: 59
Mr. Andrew P. Swiger became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.

Jack P. Williams, Jr.	Senior Vice President
Held current title since:	June 1, 2014	Age: 52
Mr. Jack P. Williams, Jr. was President of XTO Energy Inc. June 25, 2010 – May 31, 2013. He was Executive Vice President of ExxonMobil Production Company June 1, 2013 – June 30, 2014. He became Senior Vice President of Exxon Mobil Corporation on June 1, 2014, 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: 64
Mr. S. Jack Balagia became Vice President and General Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.

27

Neil A. Chapman	Vice President
Held current title since:	January 1, 2015	Age: 53
Mr. Neil A. Chapman was President of ExxonMobil Global Services Company April 4, 2007 – March 31, 2011. He was Senior Vice President, ExxonMobil Chemical Company April 1, 2011 – December 31, 2014. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on January 1, 2015, 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: 54
Mr. Randy J. Cleveland was Vice President, XTO Integration, XTO Energy Inc. June 25, 2010 – January 31, 2012. He was Executive Vice President, XTO Energy Inc. February 1, 2012 – May 31, 2013. He became President of XTO 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: 62
Mr. William M. Colton became Vice President – Corporate Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.

Bradley W. Corson	Vice President
Held current title since:	March 1, 2015	Age: 54
Mr. Bradley W. Corson was Regional Vice President, Europe/Caspian for ExxonMobil Production Company May 1, 2009 – April 30, 2014. He was Vice President, ExxonMobil Upstream Ventures May 1, 2014 – February 28, 2015. He became President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation on March 1, 2015, positions he still holds as of this filing date.

Neil W. Duffin	President, ExxonMobil Development Company
Held current title since:	April 13, 2007	Age: 59
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: 58
Mr. Robert S. Franklin was President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation May 1, 2009 – February 28, 2013. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date.

Stephen M. Greenlee	Vice President
Held current title since:	September 1, 2010	Age: 58
Mr. Stephen M. Greenlee became President of ExxonMobil Exploration Company and Vice President of Exxon 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: 58
Mr. Alan J. Kelly became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporation on December 1, 2007. On February 1, 2012, the businesses of ExxonMobil Lubricants & Petroleum Specialties Company and ExxonMobil Fuels Marketing Company were consolidated and Mr. Kelly became President of the combined ExxonMobil Fuels, Lubricants & Specialties Marketing Company and Vice President of Exxon Mobil Corporation, positions he still holds as of this filing date.

28

David S. Rosenthal	Vice President and Controller
Held current title since:	October 1, 2008 (Vice President) September 1, 2014 (Controller)	Age: 59
Mr. David S. Rosenthal was Vice President – Investor Relations and Secretary of Exxon Mobil Corporation October 1, 2008 – August 31, 2014. He became Vice President and Controller of Exxon Mobil Corporation on September 1, 2014, positions he still holds as of this filing date.

Robert N. Schleckser	Vice President and Treasurer
Held current title since:	May 1, 2011	Age: 59
Mr. Robert N. Schleckser was Assistant Treasurer of Exxon Mobil Corporation February 1, 2009 – April 30, 2011. He became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, 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: 54
Mr. James M. Spellings, Jr. became Vice President 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: 61
Mr. Thomas R. Walters was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation April 1, 2009 – February 28, 2013. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date.
Dennis G. Wascom	Vice President
Held current title since:	August 1, 2014	Age: 59
Mr. Dennis G. Wascom was Director, Refining Americas, ExxonMobil Refining & Supply Company April 1, 2009 – June 30, 2013. He was Director, Refining North America, ExxonMobil Refining & Supply Company July 1, 2013 – July 31, 2014. He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on August 1, 2014, positions he still holds as of this filing date.

Jeffrey J. Woodbury	Vice President – Investor Relations and Secretary
Held current title since:	July 1, 2011 (Vice President) September 1, 2014 (Secretary)	Age: 55
Mr. Jeffrey J. Woodbury was Executive Vice President of ExxonMobil Development Company April 1, 2009 – June 30, 2011. He was Vice President, Safety, Security, Health and Environment of Exxon Mobil Corporation July 1, 2011 – August 31, 2014. He became Vice President – Investor Relations and Secretary of Exxon Mobil Corporation on September 1, 2014, positions he still holds as of this filing 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 until a successor has been elected and qualified.

29

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, 2015
				Total Number of
				Shares
				Purchased as	Maximum Number
				Part of Publicly	of Shares that May
		Total Number of	Average Price	Announced	Yet Be Purchased
		Shares	Paid per	Plans or	Under the Plans or
Period		Purchased	Share	Programs	Programs
October 2015		2,251,296	79.78	2,251,296
November 2015		3,845,713	81.66	3,845,713
December 2015		3,292,255	79.01	3,292,255
	Total	9,389,264	80.28	9,389,264	(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 shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated February 2, 2016, the Corporation stated it will continue to acquire shares to offset dilution in conjunction with benefit plans and programs, but does not plan on making purchases to reduce shares outstanding.

Item 6.       Selected Financial Data

	Years Ended December 31,
	2015	2014	2013	2012	2011
	(millions of dollars, except per share amounts)
Sales and other operating revenue (1)	259,488	394,105	420,836	451,509	467,029
(1) Sales-based taxes included	22,678	29,342	30,589	32,409	33,503
Net income attributable to ExxonMobil	16,150	32,520	32,580	44,880	41,060
Earnings per common share	3.85	7.60	7.37	9.70	8.43
Earnings per common share - assuming dilution	3.85	7.60	7.37	9.70	8.42
Cash dividends per common share	2.88	2.70	2.46	2.18	1.85
Total assets	336,758	349,493	346,808	333,795	331,052
Long-term debt	19,925	11,653	6,891	7,928	9,322

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

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial Section 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 Uncertainties,” in the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

30

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 24, 2016, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 19: Income, Sales-Based and Other 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 financial 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 Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2015. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in 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 allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported 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 responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2015.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2015, 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 Corporation’s internal control over financial reporting.

Item 9B.     Other Information

None.

31

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 2016 annual meeting of shareholders (the “2016 Proxy 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 Stock Ownership”;

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

· The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Meeting 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 Analysis” and “Executive Compensation Tables” of the registrant’s 2016 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 Ownership” and “Certain Beneficial Owners” of the registrant’s 2016 Proxy Statement.

Equity Compensation Plan Information
		(a)		(b)	(c)
					Number of Securities
				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		31,090,370	(1)	-	100,899,852	(2)(3)
Equity compensation plans not approved by security holders		-		-	-
	Total	31,090,370		-	100,899,852

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

(2)   Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 100,324,152 shares available for award under the 2003 Incentive Program and 575,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

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

32

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 entitled “Corporate Governance” of the registrant’s 2016 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 “Ratification of Independent Auditors” of the registrant’s 2016 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.

33

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	40
Overview	40
Business Environment and Risk Assessment	41
Review of 2015 and 2014 Results	44
Liquidity and Capital Resources	48
Capital and Exploration Expenditures	53
Taxes	53
Environmental Matters	54
Market Risks, Inflation and Other Uncertainties	54
Recently Issued Accounting Standards	56
Critical Accounting Estimates	56
Management’s Report on Internal Control Over Financial Reporting	61
Report of Independent Registered Public Accounting Firm	62
Consolidated Financial Statements
Statement of Income	63
Statement of Comprehensive Income	64
Balance Sheet	65
Statement of Cash Flows	66
Statement of Changes in Equity	67
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies	68
2. Accounting Changes	71
3. Miscellaneous Financial Information	71
4. Other Comprehensive Income Information	72
5. Cash Flow Information	73
6. Additional Working Capital Information	73
7. Equity Company Information	74
8. Investments, Advances and Long-Term Receivables	75
9. Property, Plant and Equipment and Asset Retirement Obligations	76
10. Accounting for Suspended Exploratory Well Costs	77
11. Leased Facilities	79
12. Earnings Per Share	79
13. Financial Instruments and Derivatives	80
14. Long-Term Debt	81
15. Incentive Program	82
16. Litigation and Other Contingencies	83
17. Pension and Other Postretirement Benefits	85
18. Disclosures about Segments and Related Information	93
19. Income, Sales-Based and Other Taxes	96
Supplemental Information on Oil and Gas Exploration and Production Activities	99
Operating Summary	114

34

BUSINESS PROFILE

							Return on			Capital and
			Earnings After		Average Capital		Average Capital			Exploration
			Income Taxes		Employed		Employed			Expenditures
Financial			2015	2014	2015	2014	2015	2014		2015	2014
			(millions of dollars)				(percent)		(millions of dollars)
Upstream
	United States		(1,079)	5,197	64,086	62,403	(1.7)	8.3		7,822	9,401
	Non-U.S.		8,180	22,351	105,868	102,562	7.7	21.8		17,585	23,326
		Total	7,101	27,548	169,954	164,965	4.2	16.7		25,407	32,727
Downstream
	United States		1,901	1,618	7,497	6,070	25.4	26.7		1,039	1,310
	Non-U.S.		4,656	1,427	15,756	17,907	29.6	8.0		1,574	1,724
		Total	6,557	3,045	23,253	23,977	28.2	12.7		2,613	3,034
Chemical
	United States		2,386	2,804	7,696	6,121	31.0	45.8		1,945	1,690
	Non-U.S.		2,032	1,511	16,054	16,076	12.7	9.4		898	1,051
		Total	4,418	4,315	23,750	22,197	18.6	19.4		2,843	2,741
Corporate and financing			(1,926)	(2,388)	(8,202)	(8,029)	-	-		188	35
		Total	16,150	32,520	208,755	203,110	7.9	16.2		31,051	38,537

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

Operating			2015	2014				2015	2014
		(thousands of barrels daily)					(thousands of barrels daily)
Net liquids production					Refinery throughput
	United States		476	454		United States		1,709	1,809
	Non-U.S.		1,869	1,657		Non-U.S.		2,723	2,667
		Total	2,345	2,111			Total	4,432	4,476
		(millions of cubic feet daily)					(thousands of barrels daily)
Natural gas production available for sale					Petroleum product sales (2)
	United States		3,147	3,404		United States		2,521	2,655
	Non-U.S.		7,368	7,741		Non-U.S.		3,233	3,220
		Total	10,515	11,145			Total	5,754	5,875
		(thousands of oil-equivalent barrels daily)					(thousands of metric tons)
Oil-equivalent production (1)			4,097	3,969	Chemical prime product sales (2)(3)
						United States		9,664	9,528
						Non-U.S.		15,049	14,707
							Total	24,713	24,235

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

(2)Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty. 

(3)Prime product sales are total product sales excluding carbon black oil and sulfur. Prime product sales include ExxonMobil´s share of equity company volumes and finished-product transfers to the Downstream.

35

FINANCIAL SUMMARY

			2015	2014	2013	2012	2011
		(millions of dollars, except per share amounts)
Sales and other operating revenue (1)			259,488	394,105	420,836	451,509	467,029
Earnings
	Upstream		7,101	27,548	26,841	29,895	34,439
	Downstream		6,557	3,045	3,449	13,190	4,459
	Chemical		4,418	4,315	3,828	3,898	4,383
	Corporate and financing		(1,926)	(2,388)	(1,538)	(2,103)	(2,221)
	Net income attributable to ExxonMobil		16,150	32,520	32,580	44,880	41,060
Earnings per common share			3.85	7.60	7.37	9.70	8.43
Earnings per common share – assuming dilution			3.85	7.60	7.37	9.70	8.42
Cash dividends per common share			2.88	2.70	2.46	2.18	1.85
Earnings to average ExxonMobil share of equity (percent)			9.4	18.7	19.2	28.0	27.3
Working capital			(11,353)	(11,723)	(12,416)	321	(4,542)
Ratio of current assets to current liabilities (times)			0.79	0.82	0.83	1.01	0.94
Additions to property, plant and equipment			27,475	34,256	37,741	35,179	33,638
Property, plant and equipment, less allowances			251,605	252,668	243,650	226,949	214,664
Total assets			336,758	349,493	346,808	333,795	331,052
Exploration expenses, including dry holes			1,523	1,669	1,976	1,840	2,081
Research and development costs			1,008	971	1,044	1,042	1,044
Long-term debt			19,925	11,653	6,891	7,928	9,322
Total debt			38,687	29,121	22,699	11,581	17,033
Fixed-charge coverage ratio (times)			17.6	46.9	55.7	62.4	53.4
Debt to capital (percent)			18.0	13.9	11.2	6.3	9.6
Net debt to capital (percent) (2)			16.5	11.9	9.1	1.2	2.6
ExxonMobil share of equity at year-end			170,811	174,399	174,003	165,863	154,396
ExxonMobil share of equity per common share			41.10	41.51	40.14	36.84	32.61
Weighted average number of common shares
	outstanding (millions)		4,196	4,282	4,419	4,628	4,870
Number of regular employees at year-end (thousands) (3)			73.5	75.3	75.0	76.9	82.1
CORS employees not included above (thousands) (4)			2.1	8.4	9.8	11.1	17.0

(1)   Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014, $30,589 million for 2013, $32,409 million for 2012 and $33,503 million for 2011.

(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 for the Corporation and are covered by the Corporation’s benefit plans and programs.

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

36

FREQUENTLY USED TERMS

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

Cash Flow From Operations and Asset Sales

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

Cash flow from operations and asset sales		2015	2014	2013
		(millions of dollars)
Net cash provided by operating activities		30,344	45,116	44,914
Proceeds associated with sales of subsidiaries, property, plant and equipment,
	and sales and returns of investments	2,389	4,035	2,707
	Cash flow from operations and asset sales	32,733	49,151	47,621

Capital Employed

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

Capital employed		2015	2014	2013
		(millions of dollars)
Business uses: asset and liability perspective
Total assets		336,758	349,493	346,808
Less liabilities and noncontrolling interests share of assets and liabilities
	Total current liabilities excluding notes and loans payable	(35,214)	(47,165)	(55,916)
	Total long-term liabilities excluding long-term debt	(86,047)	(92,143)	(87,698)
	Noncontrolling interests share of assets and liabilities	(8,286)	(9,099)	(8,935)
Add ExxonMobil share of debt-financed equity company net assets		4,447	4,766	6,109
	Total capital employed	211,658	205,852	200,368
Total corporate sources: debt and equity perspective
Notes and loans payable		18,762	17,468	15,808
Long-term debt		19,925	11,653	6,891
ExxonMobil share of equity		170,811	174,399	174,003
Less noncontrolling interests share of total debt		(2,287)	(2,434)	(2,443)
Add ExxonMobil share of equity company debt		4,447	4,766	6,109
	Total capital employed	211,658	205,852	200,368

37

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

Return on average capital employed				2015	2014	2013
				(millions of dollars)
Net income attributable to ExxonMobil				16,150	32,520	32,580
Financing costs (after tax)
	Gross third-party debt			(362)	(140)	(163)
	ExxonMobil share of equity companies			(170)	(256)	(239)
	All other financing costs – net			88	(68)	83
		Total financing costs		(444)	(464)	(319)
			Earnings excluding financing costs	16,594	32,984	32,899
Average capital employed				208,755	203,110	191,575
Return on average capital employed – corporate total				7.9%	16.2%	17.2%

38

QUARTERLY INFORMATION

		2015					2014
		First	Second	Third	Fourth		First	Second	Third	Fourth
		Quarter	Quarter	Quarter	Quarter	Year	Quarter	Quarter	Quarter	Quarter	Year
Volumes
Production of crude oil,		(thousands of barrels daily)
	natural gas liquids,	2,277	2,291	2,331	2,481	2,345	2,148	2,048	2,065	2,182	2,111
	synthetic oil and bitumen
Refinery throughput		4,546	4,330	4,457	4,395	4,432	4,509	4,454	4,591	4,349	4,476
Petroleum product sales (1)		5,814	5,737	5,788	5,679	5,754	5,817	5,841	5,999	5,845	5,875
Natural gas production		(millions of cubic feet daily)
	available for sale	11,828	10,128	9,524	10,603	10,515	12,016	10,750	10,595	11,234	11,145
		(thousands of oil-equivalent barrels daily)
Oil-equivalent production (2)		4,248	3,979	3,918	4,248	4,097	4,151	3,840	3,831	4,054	3,969
		(thousands of metric tons)
Chemical prime product sales (1) (3)		6,069	6,078	6,082	6,484	24,713	6,128	6,139	6,249	5,719	24,235
Summarized financial data
Sales and other operating		(millions of dollars)
	revenue (4)	64,758	71,360	65,679	57,691	259,488	101,312	105,719	103,206	83,868	394,105
Gross profit (5)		19,030	20,362	20,247	16,211	75,850	29,166	28,746	28,825	23,240	109,977
Net income attributable to
	ExxonMobil	4,940	4,190	4,240	2,780	16,150	9,100	8,780	8,070	6,570	32,520
Per share data		(dollars per share)
Earnings per common share (6)		1.17	1.00	1.01	0.67	3.85	2.10	2.05	1.89	1.56	7.60
Earnings per common share
	– assuming dilution (6)	1.17	1.00	1.01	0.67	3.85	2.10	2.05	1.89	1.56	7.60
Dividends per common share		0.69	0.73	0.73	0.73	2.88	0.63	0.69	0.69	0.69	2.70
Common stock prices
	High	93.45	90.09	83.53	87.44	93.45	101.22	104.61	104.76	97.20	104.76
	Low	82.68	82.80	66.55	73.03	66.55	89.25	96.24	93.62	86.19	86.19

(1)   Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.

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

(3)   Prime product sales are total product sales excluding carbon black oil and sulfur. Prime product sales include ExxonMobil’s share of equity company volumes and finished-product transfers to the Downstream.

(4)   Includes amounts for sales-based taxes.

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

(6)   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 stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

There were 419,510 registered shareholders of ExxonMobil common stock at December 31, 2015. At January 31, 2016, the registered shareholders of ExxonMobil common stock numbered 418,587.

On January 27, 2016, the Corporation declared a $0.73 dividend per common share, payable March 10, 2016.

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

FUNCTIONAL EARNINGS			2015	2014	2013
			(millions of dollars, except per share amounts)
Earnings (U.S. GAAP)
Upstream
	United States		(1,079)	5,197	4,191
	Non-U.S.		8,180	22,351	22,650
Downstream
	United States		1,901	1,618	2,199
	Non-U.S.		4,656	1,427	1,250
Chemical
	United States		2,386	2,804	2,755
	Non-U.S.		2,032	1,511	1,073
Corporate and financing			(1,926)	(2,388)	(1,538)
		Net income attributable to ExxonMobil (U.S. GAAP)	16,150	32,520	32,580
Earnings per common share			3.85	7.60	7.37
Earnings per common share – assuming dilution			3.85	7.60	7.37

References in this discussion to total corporate earnings mean net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income statement. Unless otherwise indicated, references to earnings, Upstream, Downstream, Chemical and Corporate and Financing segment earnings, and earnings per share are ExxonMobil’s share after excluding amounts attributable to noncontrolling interests.

FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future financial and operating results, including demand growth and energy source mix; capacity increases; production growth and mix; rates of field decline; financing sources; the resolution of contingencies and uncertain tax positions; environmental and capital expenditures; could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products and resulting price impacts; the outcome of commercial negotiations; the impact of fiscal and commercial terms; political or 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 government 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 consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, reduces the Corporation’s risk from changes in commodity prices. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined products, and chemical products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are evaluated over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

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

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2040, the world’s population is projected to grow to approximately 9 billion people, or about 1.8 billion more than in 2014. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. As economies and populations grow, and as living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 25 percent from 2014 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that are not 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 practices will continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2040, affecting energy requirements for transportation, power generation, industrial applications, and residential and commercial needs.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 30 percent from 2014 to 2040. The growth in transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period. Nearly all the world’s transportation fleets will continue to run on liquid fuels, which are abundant, widely available, easy to transport, and provide a large quantity of energy in small volumes.

Demand for electricity around the world is likely to increase approximately 65 percent from 2014 to 2040, led by growth in developing countries. Consistent with this projection, power generation is expected to remain the largest and fastest‑growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Today, coal‑fired generation provides about 40 percent of the world’s electricity, but by 2040 its share is likely to decline to about 30 percent, in part as a result of policies to improve air quality and reduce greenhouse gas emissions and the risks of climate change. From 2014 to 2040, the amount of electricity generated using natural gas, nuclear power, and renewables are all likely to double. By 2040, coal, natural gas and renewables are projected to be generating approximately the same share of electricity worldwide, although significant differences will exist across regions reflecting a wide range of factors including the cost and availability of energy types.

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability and ease of transportation, distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is projected to grow to approximately 112 million barrels of oil‑equivalent per day, an increase of about 20 percent from 2014. Globally, crude production from traditional conventional sources will likely decrease slightly through 2040, with significant development activity mostly offsetting natural declines from these fields. However, this decrease is expected to be more than offset by rising production from a variety of emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely 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 it is expected to be the fastest-growing major fuel source from 2014 to 2040, meeting about 40 percent of global energy demand growth. Global natural gas demand is expected to rise about 50 percent from 2014 to 2040, with about 45 percent of that increase in the Asia Pacific region. Helping meet these needs will be significant growth in supplies of unconventional gas ‑ the natural gas found in shale and other rock formations that was once considered uneconomic to produce. In total, about 60 percent of the growth in natural gas supplies is expected to be from unconventional sources. However, we expect conventionally-produced natural gas to remain the cornerstone of supply, meeting about two‑thirds of global demand in 2040. The worldwide liquefied natural gas (LNG) market is expected to almost triple by 2040, with much of this supply expected to meet rising demand in Asia Pacific.

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 remaining 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 in the 2025‑2030 timeframe. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to about 20 percent. Nuclear power is projected to grow significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to reach about 15 percent of total energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing close to 250 percent from 2014 to 2040, when they will be approaching 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 increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet oil and natural

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

gas supply requirements worldwide over the period 2015‑2040 will be about $25 trillion (measured in 2014 dollars) or approximately $1 trillion per year on average.

International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into account policies established to reduce energy‑related greenhouse gas emissions in its long-term Outlook for Energy, which is used as a foundation for assessing the business environment and business strategies and investments. The climate accord reached at the recent Conference of the Parties (COP 21) in Paris set many new goals, and while many related policies are still emerging, the Outlook for Energy continues to anticipate that such policies will increase the cost of carbon dioxide emissions over time. For purposes of the Outlook for Energy, we continue to assume that governments will enact policies that impose rising costs on energy‑related CO₂ emissions, which we assume will reach an implied cost in OECD nations of about $80 per tonne in 2040. China and other leading non‑OECD nations are expected to trail OECD policy initiatives. Nevertheless, as people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. Thus, all practical and economically viable energy sources, both conventional and unconventional, will be needed to continue meeting global energy needs – because of the scale of worldwide energy demand.

The information provided in the Long‑Term Business Outlook includes ExxonMobil’s internal estimates and forecasts based upon internal data and 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 selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include capturing material and accretive opportunities to continually high-grade the resource portfolio, exercising a disciplined approach to investing and cost management, developing and applying high-impact technologies, pursuing productivity and efficiency gains, growing profitable oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees, and investment in the communities within which we operate.

As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix and in the type of opportunities from which volumes are produced. Oil equivalent production from North America is expected to increase over the next several years based on current capital activity plans, contributing over a third of total production. Further, the proportion of our global production from resource types utilizing specialized technologies such as arctic, deepwater, and unconventional drilling and production systems, as well as LNG, is also expected to grow, becoming a slight majority of production in the next few years. We do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a material 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 expenses.

The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.

The upstream industry environment has been challenged throughout 2015 with abundant crude oil supply causing crude oil prices to decrease to levels not seen since 2004, while natural gas prices remained depressed. However, current market conditions are not necessarily indicative of future conditions. The markets for crude oil and natural gas have a history of significant price volatility. ExxonMobil believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of global economic growth. On the supply side, prices may be significantly impacted by political events, the actions of OPEC and other large government resource owners, and other factors. To manage the risks associated with price, ExxonMobil evaluates annual plans and all investments across a wide range of price scenarios. The Corporation’s assessment is that its operations will exhibit strong performance over the long term. This is the outcome of disciplined investment, cost management, asset enhancement programs, and application of advanced technologies.

Downstream

ExxonMobil’s Downstream is a large, diversified business with refining, logistics, and marketing complexes around the world. The Corporation has a presence in mature markets in North America and Europe, as well as in the growing Asia Pacific region.

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

ExxonMobil’s fundamental Downstream business strategies competitively position the company across a range of market conditions. These strategies include targeting best‑in‑class operations in all aspects of the business, maximizing value from advanced technologies, capitalizing on integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers.

ExxonMobil’s operating results, as noted in Item 2. Properties, reflect 23 refineries, located in 14 countries, with distillation capacity of 5 million barrels per day and lubricant basestock manufacturing capacity of 136 thousand barrels per day. ExxonMobil’s fuels and lubes marketing businesses have significant global reach, with 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 improved in 2015. Growth in global demand, stimulated by lower prices for crude oil and transportation fuels, resulted in higher refinery utilization and margins, particularly in Europe and Asia Pacific. Refineries in North America continue to benefit from lower raw material and energy costs due to the abundant supply of crude oil and natural gas. In the near term, we see variability in refining margins, with some regions seeing weaker margins as new capacity additions are expected to outpace growth in global demand for our products, which can also be affected by global economic conditions and regulatory changes.

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

ExxonMobil’s long‑term outlook is that industry refining margins will remain subject to intense competition as new capacity additions outpace the growth in global demand. ExxonMobil’s integration across the value chain, from refining to marketing, enhances overall value in both fuels and lubricants businesses.

As described in more detail in Item 1A. Risk Factors, proposed carbon policy and other climate‑related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the Downstream business

In the retail fuels marketing business, competition has caused inflation‑adjusted margins to decline. In 2015, ExxonMobil expanded its branded retail site network and progressed the multi‑year transition of the direct served (i.e., dealer, company‑operated) retail network in portions of Europe to a more capital‑efficient Branded Wholesaler model. The company’s lubricants business continues to grow, leveraging world‑class brands and integration with industry‑leading basestock refining capability. ExxonMobil remains a market leader in the high‑value synthetic lubricants sector, despite increasing competition.

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. In 2015, the company divested its 50 percent share of Chalmette Refining, LLC, and reached an agreement for the sale of the refinery in Torrance, California, with change-in-control expected by mid-2016. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. In 2015, construction continued on a new delayed coker unit at the refinery in Antwerp, Belgium, to upgrade low‑value bunker fuel into higher value diesel products. Funding was approved for the construction of a proprietary hydrocracker at the refinery in Rotterdam, Netherlands, to produce higher value ultra‑low sulfur diesel and Group II basestocks. The company completed an expansion of lubricant basestock capacity at the refinery in Baytown, Texas. Finished lubricant plant expansions in China and Finland were completed, and an expansion in Singapore is underway to support demand growth for finished lubricants and greases in key markets.

Chemical

Worldwide petrochemical demand continued to improve in 2015, led by growing demand from Asia Pacific manufacturers of industrial and consumer products. North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low‑cost feedstock and energy. Specialty product margins improved in 2015, but continued to be impacted by new industry capacity.

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

In 2015, we neared completion of the specialty elastomers project at our joint venture facility in Al-Jubail, Saudi Arabia. Construction continued on a major expansion at our Texas facilities, including a new world-scale ethane cracker and polyethylene lines, to capitalize on low-cost feedstock and energy supplies in North America and to meet rapidly growing demand for premium polymers. Construction of new halobutyl rubber and hydrocarbon resin units also progressed in Singapore to further extend our specialty product capacity in Asia Pacific.

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

REVIEW OF 2015 AND 2014 RESULTS
	2015	2014	2013
	(millions of dollars)
Earnings (U.S. GAAP)
Net income attributable to ExxonMobil (U.S. GAAP)	16,150	32,520	32,580

Upstream
			2015	2014	2013
			(millions of dollars)
Upstream
	United States		(1,079)	5,197	4,191
	Non-U.S.		8,180	22,351	22,650
		Total	7,101	27,548	26,841

2015

Upstream earnings were $7,101 million, down $20,447 million from 2014. Lower realizations decreased earnings by $18.8 billion. Favorable volume and mix effects increased earnings by $810 million, including contributions from new developments. All other items decreased earnings by $2.4 billion, primarily due to lower asset management gains and approximately $500 million of lower favorable one‑time tax effects, partly offset by lower expenses of about $230 million.On an oil‑equivalent basis, production of 4.1 million barrels per day was up 3.2 percent compared to 2014. Liquids production of 2.3 million barrels per day increased 234,000 barrels per day, with project ramp‑up and entitlement effects partly offset by field decline. Natural gas production of 10.5 billion cubic feet per day decreased 630 million cubic feet per day from 2014 as regulatory restrictions in the Netherlands and field decline were partly offset by project ramp‑up, work programs and entitlement effects.U.S. Upstream earnings declined $6,276 million from 2014 to a loss of $1,079 million in 2015. Earnings outside the U.S. were $8,180 million, down $14,171 million from the prior year.

2014

Upstream earnings were $27,548 million, up $707 million from 2013. Lower prices decreased earnings by $2 billion. Favorable volume effects increased earnings by $510 million. All other items, primarily asset sales and favorable U.S. deferred income tax items, increased earnings by $2.2 billion. On an oil‑equivalent basis, production of 4 million barrels per day was down 4.9 percent compared to 2013. Excluding the impact of the expiry of the Abu Dhabi onshore concession, production decreased 1.7 percent. Liquids production of 2.1 million barrels per day decreased 91,000 barrels per day compared to 2013. The Abu Dhabi onshore concession expiry reduced volumes by 135,000 barrels per day. Excluding this impact, liquids production was up 2 percent, driven by project ramp‑up and work programs. Natural gas production of 11.1 billion cubic feet per day decreased 691 million cubic feet per day from 2013, as expected U.S. field decline and lower European demand were partially offset by project ramp‑up and work programs. Earnings from U.S. Upstream operations were $5,197 million, up $1,006 million from 2013. Earnings outside the U.S. were $22,351 million, down $299 million from the prior year.

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

Upstream Additional Information
		2015	2014
		(thousands of barrels daily)
Volumes Reconciliation (Oil-equivalent production)(1)
Prior year		3,969	4,175
	Entitlements - Net Interest	(14)	(4)
	Entitlements - Price / Spend / Other	168	(43)
	Quotas	-	-
	Divestments	(25)	(31)
	United Arab Emirates Onshore Concession Expiry	(6)	(135)
	Growth / Other	5	7
Current Year		4,097	3,969
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

Listed below are descriptions of ExxonMobil’s volumes reconciliation factors which are provided to facilitate understanding of the terms.

Entitlements - Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to volume-determining factors. These factors consist of net interest changes specified in Production Sharing Contracts (PSCs) which typically occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon achieving pay-out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result of the termination or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices.

Entitlements - Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes to non-operational volume-determining factors. These factors include changes in oil and gas prices or spending levels from one period to another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or market prices for oil and natural gas. Such factors can also include other temporary changes in net interest as dictated by specific provisions in production agreements.

Quotas are changes in ExxonMobil’s allowable production arising from production constraints imposed by countries which are members of the Organization of the Petroleum Exporting Countries (OPEC). Volumes reported in this category would have been readily producible in the absence of the quota.

Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity in a field or asset in exchange for financial or other economic consideration.

Growth and Other factors comprise all other operational and non-operational factors not covered by the above definitions that may affect volumes attributable to ExxonMobil. Such factors include, but are not limited to, production enhancements from project and work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline, and any fiscal or commercial terms that do not affect entitlements.

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

Downstream
			2015	2014	2013
			(millions of dollars)
Downstream
	United States		1,901	1,618	2,199
	Non-U.S.		4,656	1,427	1,250
		Total	6,557	3,045	3,449

2015

Downstream earnings of $6,557 million increased $3,512 million from 2014. Stronger margins increased earnings by $4.1 billion, while volume and mix effects decreased earnings by $200 million. All other items decreased earnings by $420 million, reflecting nearly $560 million in higher maintenance expense and about $280 million in unfavorable inventory impacts, partly offset by favorable foreign exchange effects. Petroleum product sales of 5.8 million barrels per day were 121,000 barrels per day lower than 2014.U.S. Downstream earnings were $1,901 million, an increase of $283 million from 2014. Non‑U.S. Downstream earnings were $4,656 million, up $3,229 million from the prior year.

2014

Downstream earnings of $3,045 million decreased $404 million from 2013. Lower margins decreased earnings by $230 million. Volume and mix effects increased earnings by $480 million. All other items, primarily unfavorable foreign exchange and tax impacts, partially offset by lower expenses, decreased earnings by $650 million. Petroleum product sales of 5.9 million barrels per day were in line with 2013. U.S. Downstream earnings were $1,618 million, a decrease of $581 million from 2013. Non‑U.S. Downstream earnings were $1,427 million, up $177 million from the prior year.

Chemical
			2015	2014	2013
			(millions of dollars)
Chemical
	United States		2,386	2,804	2,755
	Non-U.S.		2,032	1,511	1,073
		Total	4,418	4,315	3,828

2015

Chemical earnings of $4,418 million increased $103 million from 2014. Stronger margins increased earnings by $590 million. Favorable volume and mix effects increased earnings by $220 million. All other items decreased earnings by $710 million, reflecting about $680 million in unfavorable foreign exchange effects and $220 million in negative tax and inventory impacts, partly offset by asset management gains. Prime product sales of 24.7 million metric tons were up 478,000 metric tons from 2014.U.S. Chemical earnings were $2,386 million, down $418 million from 2014. Non‑U.S. Chemical earnings were $2,032 million, $521 million higher than the prior year.

2014

Chemical earnings of $4,315 million increased $487 million from 2013. Higher commodity‑driven margins increased earnings by $520 million, while volume and mix effects increased earnings by $100 million. All other items, primarily higher planned expenses, decreased earnings by $130 million. Prime product sales of 24.2 million metric tons were up 172,000 metric tons from 2013, driven by increased Singapore production. U.S. Chemical earnings were $2,804 million, up $49 million from 2013. Non‑U.S. Chemical earnings were $1,511 million, $438 million higher than the prior year.

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

Corporate and Financing
	2015	2014	2013
	(millions of dollars)
Corporate and financing	(1,926)	(2,388)	(1,538)

2015

Corporate and financing expenses were $1,926 million in 2015 compared to $2,388 million in 2014, with the decrease due mainly to net favorable tax‑related items.

2014

Corporate and financing expenses were $2,388 million in 2014, up $850 million from 2013 due primarily to tax‑related items.

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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
		2015	2014	2013
		(millions of dollars)
Net cash provided by/(used in)
	Operating activities	30,344	45,116	44,914
	Investing activities	(23,824)	(26,975)	(34,201)
	Financing activities	(7,037)	(17,888)	(15,476)
Effect of exchange rate changes		(394)	(281)	(175)
Increase/(decrease) in cash and cash equivalents		(911)	(28)	(4,938)
		(December 31)
Cash and cash equivalents		3,705	4,616	4,644
Cash and cash equivalents - restricted		-	42	269
Total cash and cash equivalents		3,705	4,658	4,913

Total cash and cash equivalents were $3.7 billion at the end of 2015, $1.0 billion lower than the prior year. The major sources of funds in 2015 were net income including noncontrolling interests of $16.6 billion, the adjustment for the noncash provision of $18.0 billion for depreciation and depletion, and a net debt increase of $9.3 billion. The major uses of funds included spending for additions to property, plant and equipment of $26.5 billion, the purchase of shares of ExxonMobil stock of $4.0 billion, dividends to shareholders of $12.1 billion and a change in working capital, excluding cash and debt, of $3.1 billion.

Total cash and cash equivalents were $4.7 billion at the end of 2014, $0.3 billion lower than the prior year. The major sources of funds in 2014 were net income including noncontrolling interests of $33.6 billion, the adjustment for the noncash provision of $17.3 billion for depreciation and depletion, a net debt increase of $7.0 billion and collection of advances of $3.3 billion. The major uses of funds included spending for additions to property, plant and equipment of $33.0 billion, the purchase of shares of ExxonMobil stock of $13.2 billion, dividends to shareholders of $11.6 billion and a change in working capital, excluding cash and debt, of $4.9 billion. Included in total cash and cash equivalents at year-end 2014 was $42 million 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 majority of financial requirements, supplemented by long-term and short-term debt. On December 31, 2015, the Corporation had unused committed short-term lines of credit of $6.0 billion and unused committed long-term lines of credit of $0.4 billion. Cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure it is secure and readily available to meet the 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 apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the 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 existing oil 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 next few 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 properties, recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms.

The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunities and project execution. On average over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset sales; weather events; price effects on production sharing contracts; and changes in the amount and timing of investments that may vary depending on the oil and gas price environment. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.

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

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2015 were $31.1 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment level of $23.2 billion in 2016. The Corporation is emerging from several years of high capital expenditure levels that supported major long-plateau production projects coming on line. Lower levels of capital spending over the next few years, partly due to cost savings and capital efficiencies, are not expected to delay major project schedules nor have a material effect on our volume capacity outlook.

Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.

Cash Flow from Operating Activities

2015

Cash provided by operating activities totaled $30.3 billion in 2015, $14.8 billion lower than 2014. The major source of funds was net income including noncontrolling interests of $16.6 billion, a decrease of $17.1 billion. The noncash provision for depreciation and depletion was $18.0 billion, up $0.8 billion from the prior year. The adjustment for net gains on asset sales was $0.2 billion compared to an adjustment of $3.2 billion in 2014. Changes in operational working capital, excluding cash and debt, decreased cash in 2015 by $3.1 billion.

2014

Cash provided by operating activities totaled $45.1 billion in 2014, $0.2 billion higher than 2013. The major source of funds was net income including noncontrolling interests of $33.6 billion, an increase of $0.2 billion. The noncash provision for depreciation and depletion was $17.3 billion, up $0.1 billion from the prior year. The adjustment for net gains on asset sales was $3.2 billion compared to an adjustment of $1.8 billion in 2013. Changes in operational working capital, excluding cash and debt, decreased cash in 2014 by $4.9 billion.

Cash Flow from Investing Activities

2015

Cash used in investment activities netted to $23.8 billion in 2015, $3.2 billion lower than 2014. Spending for property, plant and equipment of $26.5 billion decreased $6.5 billion from 2014. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $2.4 billion compared to $4.0 billion in 2014. Additional investments and advances were $1.0 billion lower in 2015, while collection of advances was $2.5 billion lower in 2015.

2014

Cash used in investment activities netted to $27.0 billion in 2014, $7.2 billion lower than 2013. Spending for property, plant and equipment of $33.0 billion decreased $0.7 billion from 2013. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $4.0 billion compared to $2.7 billion in 2013. Additional investments and advances were $2.8 billion lower in 2014, while collection of advances was $2.2 billion higher in 2014.

49

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

Cash Flow from Financing Activities

2015

Cash used in financing activities was $7.0 billion in 2015, $10.9 billion lower than 2014. Dividend payments on common shares increased to $2.88 per share from $2.70 per share and totaled $12.1 billion, a pay-out of 75 percent of net income. During the first quarter of 2015, the Corporation issued $8.0 billion of long-term debt. Total debt increased $9.6 billion to $38.7 billion at year‑end.

ExxonMobil share of equity decreased $3.6 billion to $170.8 billion. The addition to equity for earnings was $16.2 billion. This was offset by reductions for distributions to ExxonMobil shareholders of $15.1 billion, composed of $12.1 billion in dividends and $3.0 billion of share purchases of ExxonMobil stock to reduce shares outstanding. Foreign exchange translation effects of $8.2 billion for the stronger U.S. currency reduced equity, while a $3.6 billion change in the funded status of the postretirement benefits reserves increased equity.

During 2015, Exxon Mobil Corporation purchased 48 million shares of its common stock for the treasury at a gross cost of $4.0 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 1.1 percent from 4,201 million to 4,156 million at the end of 2015. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

2014

Cash used in financing activities was $17.9 billion in 2014, $2.4 billion higher than 2013. Dividend payments on common shares increased to $2.70 per share from $2.46 per share and totaled $11.6 billion, a pay-out of 36 percent of net income. During the first quarter of 2014, the Corporation issued $5.5 billion of long-term debt. Total debt increased $6.4 billion to $29.1 billion at year‑end.

ExxonMobil share of equity increased $0.4 billion to $174.4 billion. The addition to equity for earnings was $32.5 billion. This was offset by reductions for distributions to ExxonMobil shareholders of $23.6 billion, composed of $11.6 billion in dividends and $12.0 billion of share purchases of ExxonMobil stock to reduce shares outstanding. Foreign exchange translation effects of $5.1 billion for the stronger U.S. currency and a $3.1 billion change in the funded status of the postretirement benefits reserves also reduced equity.

During 2014, Exxon Mobil Corporation purchased 136 million shares of its common stock for the treasury at a gross cost of $13.2 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 3.1 percent from 4,335 million to 4,201 million at the end of 2014. Purchases were made in both the open market and through negotiated transactions.  

50

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, 2015. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

		Payments Due by Period
		Note			2021
		Reference		2017-	and
Commitments		Number	2016	2020	Beyond	Total
		(millions of dollars)
Long-term debt  (1)		14	-	9,902	10,023	19,925
	– Due in one year  (2)	6	558	-	-	558
Asset retirement obligations  (3)		9	871	3,760	9,073	13,704
Pension and other postretirement obligations  (4)		17	3,495	4,104	15,567	23,166
Operating leases  (5)		11	1,653	2,167	1,057	4,877
Unconditional purchase obligations  (6)		16	133	493	310	936
Take-or-pay obligations  (7)			2,997	9,463	12,410	24,870
Firm capital commitments  (8)			10,320	4,438	441	15,199

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $9.4 billion as of December 31, 2015, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in “Note 19: Income, Sales-Based and Other Taxes.”

Notes:

(1)   Includes capitalized lease obligations of $1,238 million.

(2)   The amount due in one year is included in notes and loans payable of $18,762 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 plans at year end. The payments by period include expected contributions to funded pension plans in 2016 and estimated benefit payments for unfunded plans in all years.

(5)   Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties. Total includes $1,621 million related to drilling rigs and related equipment.

(6)   Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $936 million mainly pertain to pipeline throughput agreements and include $411 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 $24,870 million mainly pertain to pipeline, manufacturing supply and terminal agreements.

(8)   Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $15.2 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $8.0 billion was associated with projects in Africa, United Arab Emirates, Canada, Malaysia, Kazakhstan and Australia. The Corporation expects to fund the majority of these projects with internally generated funds, supplemented by long-term and short-term debt.

51

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, 2015, for guarantees relating to notes, loans and performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. These guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Financial Strength

On December 31, 2015, the Corporation’s unused short-term committed lines of credit totaled approximately $6.0 billion (Note 6) and unused long-term committed lines of credit totaled approximately $0.4 billion (Note 14). The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness.

	2015	2014	2013
Fixed-charge coverage ratio (times)	17.6	46.9	55.7
Debt to capital (percent)	18.0	13.9	11.2
Net debt to capital (percent)	16.5	11.9	9.1

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

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 pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future 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
		2015				2014
		U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total
		(millions of dollars)
Upstream (1)		7,822		17,585	25,407	9,401		23,326	32,727
Downstream		1,039		1,574	2,613	1,310		1,724	3,034
Chemical		1,945		898	2,843	1,690		1,051	2,741
Other		188		-	188	35		-	35
	Total	10,994		20,057	31,051	12,436		26,101	38,537
(1) Exploration expenses included.

Capital and exploration expenditures in 2015 were $31.1 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation anticipates an investment level of $23.2 billion in 2016. Actual spending could vary depending on the progress of individual projects and property acquisitions.

Upstream spending of $25.4 billion in 2015 was down 22 percent from 2014, reflecting key project start-ups and capital efficiencies. Investments in 2015 included projects in the U.S. Gulf of Mexico and Alaska, U.S. onshore drilling and continued progress on world-class projects in Canada and Australia. The majority of expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production. The percentage of proved developed reserves was 73 percent of total proved reserves at year-end 2015, and has been over 60 percent for the last ten years.

Capital investments in the Downstream totaled $2.6 billion in 2015, a decrease of $0.4 billion from 2014, mainly reflecting lower refining project spending. The Chemical capital expenditures of $2.8 billion increased $0.1 billion from 2014 with higher investments in the U.S.

TAXES
		2015	2014	2013
		(millions of dollars)
Income taxes		5,415	18,015	24,263
	Effective income tax rate	34%	41%	48%
Sales-based taxes		22,678	29,342	30,589
All other taxes and duties		29,790	35,515	36,396
	Total	57,883	82,872	91,248

2015

Income, sales-based and all other taxes and duties totaled $57.9 billion in 2015, a decrease of $25.0 billion or 30 percent from 2014. Income tax expense, both current and deferred, was $5.4 billion, $12.6 billion lower than 2014, as a result of lower earnings and a lower effective tax rate. The effective tax rate was 34 percent compared to 41 percent in the prior year due primarily to a lower share of earnings in higher tax jurisdictions. Sales-based and all other taxes and duties of $52.5 billion in 2015 decreased $12.4 billion as a result of lower sales realizations.

2014

Income, sales-based and all other taxes and duties totaled $82.9 billion in 2014, a decrease of $8.4 billion or 9 percent from 2013. Income tax expense, both current and deferred, was $18.0 billion, $6.2 billion lower than 2013, as a result of a lower effective tax rate. The effective tax rate was 41 percent compared to 48 percent in the prior year due primarily to impacts related to the Corporation’s asset management program and favorable U.S. deferred tax items. Sales-based and all other taxes and duties of $64.9 billion in 2014 decreased $2.1 billion.

53

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

ENVIRONMENTAL MATTERS

Environmental Expenditures
		2015	2014
		(millions of dollars)
Capital expenditures		1,869	2,666
Other expenditures		3,777	3,522
	Total	5,646	6,188

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2015 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.6 billion, of which $3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to decrease to approximately $5 billion in 2016 and 2017, mainly reflecting lower project activity in Canada. Capital expenditures are expected to account for approximately 30 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. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2015 for environmental liabilities were $371 million ($780 million in 2014) and the balance sheet reflects accumulated liabilities of $837 million as of December 31, 2015, and $1,066 million as of December 31, 2014.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

Worldwide Average Realizations(1)	2015	2014	2013
Crude oil and NGL ($/barrel)	44.77	87.42	97.48
Natural gas ($/kcf)	2.95	4.68	4.60
(1)  Consolidated subsidiaries.

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $150 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide 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 levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

54

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. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 35 percent of the Corporation’s intersegment sales represent Upstream production sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to global economic conditions, political events, decisions by OPEC and other major government resource owners and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation evaluates the viability of all of its investments over a broad range of prices. The Corporation’s assessment is that its operations will continue to be successful over the long term in a variety of 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 considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic 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 of low commodity prices.

Risk Management

The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. With respect to derivatives activities, the Corporation believes that there are no material 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. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring 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 interest 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 value. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. Some joint-venture partners are 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, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and 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-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Beginning several years ago, an extended period of increased demand for certain services and materials resulted in higher operating and capital costs. More recently, multiple market changes, including general commodity price decreases, lower oil prices and reduced upstream industry activity, have contributed to lower prices for oilfield services and materials. The Corporation works to minimize costs in all commodity price environments through its economies of scale 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

RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board issued a new standard, Revenue from Contracts with Customers. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry specific requirements, and expands disclosure requirements. The standard is required to be adopted beginning January 1, 2018.

“Sales and Other Operating Revenue” on the Consolidated Statement of Income includes sales, excise and value-added taxes on sales transactions. When the Corporation adopts the standard, revenue will exclude sales-based taxes collected on behalf of third parties. This change in reporting will not impact earnings.

The Corporation continues to evaluate other areas of the standard and its effect on the Corporation’s financial statements. 

CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The 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 about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis to calculate unit-of-production 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 analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the 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 number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 73 percent of total proved reserves at year-end 2015 (including both consolidated and equity company reserves), and has been over 60 percent for the last ten years.

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

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

56

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

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved reserves or proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used. The volumes produced and asset cost are known and, while proved reserves have a high probability of recoverability they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

Impact of Oil and Gas Reserves, Prices and Margins on Testing for Impairment. The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for this assessment.

Potential trigger events for impairment evaluation include:

·a significant decrease in the market price of a long-lived asset;

·a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

·a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

·an accumulation of project costs significantly in excess of the amount originally expected;

·a current-period operating loss combined with a history and forecast of operating or cash flow losses; and

·a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

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

If there were a trigger event, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

In light of continued weakness in the upstream industry environment in late 2015, the Corporation undertook an effort to assess its major long-lived assets most at risk for potential impairment. The results of this assessment confirm the absence of a trigger event and indicate that the future undiscounted cash flows associated with these assets substantially exceed the carrying value of the assets. The assessment reflects crude and natural gas prices that are generally consistent with the long-term price forecasts published by third-party industry experts. Critical to the long-term recoverability of certain assets is the assumption that either by supply and demand changes, or due to general inflation, prices will rise in the future. Should increases in long-term prices not materialize, certain of the Corporation’s assets will be at risk for impairment. Due to the inherent difficulty in predicting future commodity prices, and the relationship between industry prices and costs, it is not practicable to reasonably estimate a range of potential future impairments related to the Corporation’s long-lived assets.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the

57

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

properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated 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 lower or higher for any given year.

Inventories

Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). If crude oil, natural gas, petroleum product and chemical product prices continue in the range seen in early 2016, the Corporation could be subject to a lower of cost or market inventory valuation adjustment.

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, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount 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 completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells at year-end 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 share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the Corporation’s interest in the underlying net assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.

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

58

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

Pension Benefits

The Corporation and its affiliates sponsor about 100 defined benefit (pension) plans in over 40 countries. The Pension and Other Postretirement Benefits footnote (Note 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 rather than a separate pension fund because tax conventions and regulatory practices do not encourage advance funding. Book reserves are established for these plans. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

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

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

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2015 was 7.00 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 5 percent and 8 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 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 difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining 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. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these 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 reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.

Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

59

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

Tax Contingencies

The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for 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 statements if management concludes that it is more likely than not that the position will be sustained 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 that is 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 income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are 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 GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.

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

60

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 responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2015.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2015, 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)	David S. Rosenthal Vice President and Controller (Principal Accounting Officer)

61

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, Changes in Equity, and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our 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 reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 24, 2016

62

CONSOLIDATED STATEMENT OF INCOME

			Note
			Reference
			Number	2015	2014	2013
				(millions of dollars)
Revenues and other income
	Sales and other operating revenue (1)			259,488	394,105	420,836
	Income from equity affiliates		7	7,644	13,323	13,927
	Other income			1,750	4,511	3,492
		Total revenues and other income		268,882	411,939	438,255
Costs and other deductions
	Crude oil and product purchases			130,003	225,972	244,156
	Production and manufacturing expenses			35,587	40,859	40,525
	Selling, general and administrative expenses			11,501	12,598	12,877
	Depreciation and depletion			18,048	17,297	17,182
	Exploration expenses, including dry holes			1,523	1,669	1,976
	Interest expense			311	286	9
	Sales-based taxes (1)		19	22,678	29,342	30,589
	Other taxes and duties		19	27,265	32,286	33,230
		Total costs and other deductions		246,916	360,309	380,544
Income before income taxes				21,966	51,630	57,711
	Income taxes		19	5,415	18,015	24,263
Net income including noncontrolling interests				16,551	33,615	33,448
	Net income attributable to noncontrolling interests			401	1,095	868
Net income attributable to ExxonMobil				16,150	32,520	32,580
Earnings per common share (dollars)			12	3.85	7.60	7.37
Earnings per common share - assuming dilution (dollars)			12	3.85	7.60	7.37

(1)   Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

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

63

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

			2015	2014	2013
			(millions of dollars)
Net income including noncontrolling interests			16,551	33,615	33,448
Other comprehensive income (net of income taxes)
	Foreign exchange translation adjustment		(9,303)	(5,847)	(3,620)
	Adjustment for foreign exchange translation (gain)/loss
		included in net income	(14)	152	(23)
	Postretirement benefits reserves adjustment (excluding amortization)		2,358	(4,262)	3,174
	Amortization and settlement of postretirement benefits reserves
		adjustment included in net periodic benefit costs	1,448	1,111	1,820
	Unrealized change in fair value of stock investments		33	(63)	-
	Realized (gain)/loss from stock investments included in net income		27	3	-
		Total other comprehensive income	(5,451)	(8,906)	1,351
Comprehensive income including noncontrolling interests			11,100	24,709	34,799
	Comprehensive income attributable to noncontrolling interests		(496)	421	760
Comprehensive income attributable to ExxonMobil			11,596	24,288	34,039

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

64

CONSOLIDATED BALANCE SHEET

				Note
				Reference	Dec. 31	Dec. 31
				Number	2015	2014
					(millions of dollars)
Assets
	Current assets
		Cash and cash equivalents			3,705	4,616
		Cash and cash equivalents - restricted			-	42
		Notes and accounts receivable, less estimated doubtful amounts		6	19,875	28,009
		Inventories
			Crude oil, products and merchandise	3	12,037	12,384
			Materials and supplies		4,208	4,294
		Other current assets			2,798	3,565
			Total current assets		42,623	52,910
	Investments, advances and long-term receivables			8	34,245	35,239
	Property, plant and equipment, at cost, less accumulated depreciation
		and depletion		9	251,605	252,668
	Other assets, including intangibles, net				8,285	8,676
			Total assets		336,758	349,493
Liabilities
	Current liabilities
		Notes and loans payable		6	18,762	17,468
		Accounts payable and accrued liabilities		6	32,412	42,227
		Income taxes payable			2,802	4,938
			Total current liabilities		53,976	64,633
	Long-term debt			14	19,925	11,653
	Postretirement benefits reserves			17	22,647	25,802
	Deferred income tax liabilities			19	36,818	39,230
	Long-term obligations to equity companies				5,417	5,325
	Other long-term obligations				21,165	21,786
			Total liabilities		159,948	168,429
Commitments and contingencies				16
Equity
	Common stock without par value
		(9,000 million shares authorized, 8,019 million shares issued)			11,612	10,792
	Earnings reinvested				412,444	408,384
	Accumulated other comprehensive income				(23,511)	(18,957)
	Common stock held in treasury
		(3,863 million shares in 2015 and 3,818 million shares in 2014)			(229,734)	(225,820)
			ExxonMobil share of equity		170,811	174,399
	Noncontrolling interests				5,999	6,665
			Total equity		176,810	181,064
			Total liabilities and equity		336,758	349,493

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

65

CONSOLIDATED STATEMENT OF CASH FLOWS

					Note
					Reference
					Number	2015	2014	2013
						(millions of dollars)
Cash flows from operating activities
	Net income including noncontrolling interests					16,551	33,615	33,448
	Adjustments for noncash transactions
		Depreciation and depletion				18,048	17,297	17,182
		Deferred income tax charges/(credits)				(1,832)	1,540	754
		Postretirement benefits expense
			in excess of/(less than) net payments			2,153	524	2,291
		Other long-term obligation provisions
			in excess of/(less than) payments			(380)	1,404	(2,566)
	Dividends received greater than/(less than) equity in current
		earnings of equity companies				(691)	(358)	3
	Changes in operational working capital, excluding cash and debt
		Reduction/(increase)		- Notes and accounts receivable		4,692	3,118	(305)
				- Inventories		(379)	(1,343)	(1,812)
				- Other current assets		45	(68)	(105)
		Increase/(reduction)		- Accounts and other payables		(7,471)	(6,639)	(2,498)
	Net (gain) on asset sales				5	(226)	(3,151)	(1,828)
	All other items - net				5	(166)	(823)	350
		Net cash provided by operating activities				30,344	45,116	44,914
Cash flows from investing activities
	Additions to property, plant and equipment				5	(26,490)	(32,952)	(33,669)
	Proceeds associated with sales of subsidiaries, property, plant
		and equipment, and sales and returns of investments			5	2,389	4,035	2,707
	Decrease/(increase) in restricted cash and cash equivalents					42	227	72
	Additional investments and advances					(607)	(1,631)	(4,435)
	Collection of advances					842	3,346	1,124
		Net cash used in investing activities				(23,824)	(26,975)	(34,201)
Cash flows from financing activities
	Additions to long-term debt				5	8,028	5,731	345
	Reductions in long-term debt					(26)	(69)	(13)
	Additions to short-term debt					-	-	16
	Reductions in short-term debt					(506)	(745)	(756)
	Additions/(reductions) in commercial paper, and debt with
		three months or less maturity			5	1,759	2,049	12,012
	Cash dividends to ExxonMobil shareholders					(12,090)	(11,568)	(10,875)
	Cash dividends to noncontrolling interests					(170)	(248)	(304)
	Changes in noncontrolling interests					-	-	(1)
	Tax benefits related to stock-based awards					2	115	48
	Common stock acquired					(4,039)	(13,183)	(15,998)
	Common stock sold					5	30	50
		Net cash used in financing activities				(7,037)	(17,888)	(15,476)
Effects of exchange rate changes on cash						(394)	(281)	(175)
Increase/(decrease) in cash and cash equivalents						(911)	(28)	(4,938)
Cash and cash equivalents at beginning of year						4,616	4,644	9,582
Cash and cash equivalents at end of year						3,705	4,616	4,644

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

66

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

		ExxonMobil Share of Equity
					Accumulated		Common
						Other	Stock	ExxonMobil			Non-
		Common		Earnings	Comprehensive		Held in		Share of	controlling		Total
		Stock	Reinvested			Income	Treasury		Equity		Interests	Equity
		(millions of dollars)
Balance as of December 31, 2012		9,653		365,727		(12,184)	(197,333)		165,863		5,797	171,660
	Amortization of stock-based awards	761		-		-	-		761		-	761
	Tax benefits related to stock-based awards	162		-		-	-		162		-	162
	Other	(499)		-		-	-		(499)		240	(259)
	Net income for the year	-		32,580		-	-		32,580		868	33,448
	Dividends - common shares	-		(10,875)		-	-		(10,875)		(304)	(11,179)
	Other comprehensive income	-		-		1,459	-		1,459		(108)	1,351
	Acquisitions, at cost	-		-		-	(15,998)		(15,998)		(1)	(15,999)
	Dispositions	-		-		-	550		550		-	550
Balance as of December 31, 2013		10,077		387,432		(10,725)	(212,781)		174,003		6,492	180,495
	Amortization of stock-based awards	780		-		-	-		780		-	780
	Tax benefits related to stock-based awards	49		-		-	-		49		-	49
	Other	(114)		-		-	-		(114)		-	(114)
	Net income for the year	-		32,520		-	-		32,520		1,095	33,615
	Dividends - common shares	-		(11,568)		-	-		(11,568)		(248)	(11,816)
	Other comprehensive income	-		-		(8,232)	-		(8,232)		(674)	(8,906)
	Acquisitions, at cost	-		-		-	(13,183)		(13,183)		-	(13,183)
	Dispositions	-		-		-	144		144		-	144
Balance as of December 31, 2014		10,792		408,384		(18,957)	(225,820)		174,399		6,665	181,064
	Amortization of stock-based awards	828		-		-	-		828		-	828
	Tax benefits related to stock-based awards	116		-		-	-		116		-	116
	Other	(124)		-		-	-		(124)		-	(124)
	Net income for the year	-		16,150		-	-		16,150		401	16,551
	Dividends - common shares	-		(12,090)		-	-		(12,090)		(170)	(12,260)
	Other comprehensive income	-		-		(4,554)	-		(4,554)		(897)	(5,451)
	Acquisitions, at cost	-		-		-	(4,039)		(4,039)		-	(4,039)
	Dispositions	-		-		-	125		125		-	125
Balance as of December 31, 2015		11,612		412,444		(23,511)	(229,734)		170,811		5,999	176,810

			Held in
Common Stock Share Activity		Issued	Treasury	Outstanding
		(millions of shares)
Balance as of December 31, 2012		8,019	(3,517)		4,502
	Acquisitions	-	(177)		(177)
	Dispositions	-	10		10
Balance as of December 31, 2013		8,019	(3,684)		4,335
	Acquisitions	-	(136)		(136)
	Dispositions	-	2		2
Balance as of December 31, 2014		8,019	(3,818)		4,201
	Acquisitions	-	(48)		(48)
	Dispositions	-	3		3
Balance as of December 31, 2015		8,019	(3,863)		4,156

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

67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2015 presentation basis.

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the 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 included in “Investments, advances and long-term receivables.” The Corporation’s share of the net income of these companies is included in the Consolidated Statement 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 indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in Accumulated Other 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 if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

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

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

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as 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 Statement of 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 activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives 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 underlying 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 participants. 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 prices in active markets for identical assets or liabilities. Hierarchy

68

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 Level 3 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 last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

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

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.

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-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using 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 transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used.

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

The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for this assessment.

Potential trigger events for impairment evaluation include:

·a significant decrease in the market price of a long-lived asset;

·a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

·a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

·an accumulation of project costs significantly in excess of the amount originally expected;

·a current-period operating loss combined with a history and forecast of operating or cash flow losses; and

·a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

In general, the Corporation does not view temporarily low prices or margins as a trigger event for conducting impairment tests. The markets for crude oil, natural gas and petroleum products, have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand.

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted.

If there were a trigger event, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

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

Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any 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 carrying value.

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

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. 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 estimated. 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 of the 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 inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-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 units. 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.

70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2015 that had a material impact on the Corporation’s financial statements.

In May 2014, the Financial Accounting Standards Board issued a new standard, Revenue from Contracts with Customers. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry specific requirements, and expands disclosure requirements. The standard is required to be adopted beginning January 1, 2018.

“Sales and Other Operating Revenue” on the Consolidated Statement of Income includes sales, excise and value-added taxes on sales transactions. When the Corporation adopts the standard, revenue will exclude sales-based taxes collected on behalf of third parties. This change in reporting will not impact earnings.

The Corporation continues to evaluate other areas of the standard and its effect on the Corporation’s financial statements.

3. Miscellaneous Financial Information

Research and development expenses totaled $1,008 million in 2015, $971 million in 2014 and $1,044 million in 2013.

Net income included before‑tax aggregate foreign exchange transaction losses of $119 million and $225 million in 2015 and 2014, respectively, and gains of $155 million in 2013.

In 2015, 2014 and 2013, net income included a loss of $186 million, and gains of $187 million and $282 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $4.5 billion and $10.6 billion at December 31, 2015, and 2014, respectively.

Crude oil, products and merchandise as of year-end 2015 and 2014 consist of the following:

		2015	2014
		(billions of dollars)
Crude oil		4.2	4.6
Petroleum products		4.1	4.1
Chemical products		2.7	2.9
Gas/other		1.0	0.8
	Total	12.0	12.4

71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.     Other Comprehensive Income Information

		Cumulative	Post-
		Foreign	retirement	Unrealized
		Exchange	Benefits	Change in
ExxonMobil Share of Accumulated Other		Translation	Reserves	Stock
Comprehensive Income		Adjustment	Adjustment	Investments	Total
		(millions of dollars)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(3,233)	2,963	-	(270)
Amounts reclassified from accumulated other
	comprehensive income	(23)	1,752	-	1,729
Total change in accumulated other comprehensive income		(3,256)	4,715	-	1,459
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(5,258)	(4,132)	(63)	(9,453)
Amounts reclassified from accumulated other
	comprehensive income	152	1,066	3	1,221
Total change in accumulated other comprehensive income		(5,106)	(3,066)	(60)	(8,232)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(8,204)	2,202	33	(5,969)
Amounts reclassified from accumulated other
	comprehensive income	(14)	1,402	27	1,415
Total change in accumulated other comprehensive income		(8,218)	3,604	60	(4,554)
Balance as of December 31, 2015		(14,170)	(9,341)	-	(23,511)

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2015	2014	2013
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	14	(152)	23
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(2,066)	(1,571)	(2,616)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(42)	(5)	-

(1)   These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 17 – Pension and Other Postretirement Benefits for additional details.)

Income Tax (Expense)/Credit For
Components of Other Comprehensive Income		2015	2014	2013
		(millions of dollars)
Foreign exchange translation adjustment		170	292	218
Postretirement benefits reserves adjustment (excluding amortization)		(1,192)	2,009	(1,540)
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(618)	(460)	(796)
Unrealized change in fair value of stock investments		(17)	34	-
Realized change in fair value of stock investments included in net income		(15)	(2)	-
Total		(1,672)	1,873	(2,118)

72

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 maturities of three months or less when acquired are classified as cash equivalents.

For 2015, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale of service stations in Europe, the sale of Upstream properties in the U.S., the sale of ExxonMobil’s interests in Chemical and Refining joint ventures, and the pending sale of the Torrance refinery. For 2014, the amount includes before-tax gains from the sale of Hong Kong power operations, additional proceeds related to the 2013 sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale or exchange of Upstream properties in the U.S., Canada, and Malaysia. For 2013, the amount includes before-tax gains from the sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale of service stations. These net gains are reported in “Other income” on the Consolidated Statement of Income.

In 2015, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $358 million addition of commercial paper with maturity over three months. The gross amount issued was $8.1 billion, while the gross amount repaid was $7.7 billion.

In 2015, ExxonMobil completed an asset exchange that resulted in value received of approximately $500 million including $100 million in cash. The non-cash portion was not included in the “Sales of subsidiaries, investments, and property, plant and equipment” or the “All other items-net” lines on the Statement of Cash Flows. Capital leases of approximately $1 billion were not included in the “Additions to long-term debt” or “Additions to property, plant and equipment” lines on the Statement of Cash Flows.

In 2014, ExxonMobil completed asset exchanges, primarily non-cash transactions, of approximately $1.2 billion. This amount is not included in the “Sales of subsidiaries, investments, and property, plant and equipment” or the “Additions to property, plant and equipment” lines on the Statement of Cash Flows.

	2015	2014	2013
	(millions of dollars)
Cash payments for interest	586	380	426
Cash payments for income taxes	7,269	18,085	25,066

6. Additional Working Capital Information

			Dec. 31	Dec. 31
			2015	2014
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $107 million and $113 million		13,243	18,541
	Other, less reserves of $4 million and $48 million		6,632	9,468
		Total	19,875	28,009
Notes and loans payable
	Bank loans		231	473
	Commercial paper		17,973	16,225
	Long-term debt due within one year		558	770
		Total	18,762	17,468
Accounts payable and accrued liabilities
	Trade payables		18,074	25,286
	Payables to equity companies		4,639	6,589
	Accrued taxes other than income taxes		2,937	3,290
	Other		6,762	7,062
		Total	32,412	42,227

The Corporation has short-term committed lines of credit of $6.0 billion which were unused as of December 31, 2015. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was 0.4 percent and 0.3 percent at December 31, 2015, and 2014, respectively.

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, and natural gas marketing in North America; natural gas exploration, production and distribution, and downstream operations in Europe; and exploration, production, liquefied natural gas (LNG) operations, refining operations, petrochemical manufacturing, and fuel sales 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 between 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 practicable to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “income from equity affiliates.”

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 15 percent, 14 percent and 13 percent in the years 2015, 2014 and 2013, respectively.

In 2013 and 2014, the Corporation and Rosneft established various entities to conduct exploration and research activities. Periods of disproportionate funding will result in the Corporation recognizing, during the early phases of the projects, an investment that is larger than its equity share in these entities. These joint ventures are considered Variable Interest Entities. However, since the Corporation is not the primary beneficiary of these entities, the joint ventures are reported as equity companies. In 2014, the European Union and United States imposed sanctions relating to the Russian energy sector. With respect to the foregoing, each joint venture continues to comply with all applicable laws, rules and regulations. The Corporation's maximum before-tax exposure to loss from these joint ventures as of December 31, 2015, is $1.0 billion.

		2015			2014			2013
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		111,866		34,297	183,708		55,855	236,161		68,084
Income before income taxes		36,379		10,670	65,549		19,014	69,454		19,999
Income taxes		11,048		3,019	20,520		5,684	21,618		6,069
	Income from equity affiliates	25,331		7,651	45,029		13,330	47,836		13,930
Current assets		32,879		11,244	49,905		16,802	62,398		19,545
Long-term assets		109,684		32,878	110,754		33,619	116,450		35,695
	Total assets	142,563		44,122	160,659		50,421	178,848		55,240
Current liabilities		22,947		6,738	37,333		11,472	54,550		15,243
Long-term liabilities		60,388		17,165	66,231		19,470	68,857		20,873
	Net assets	59,228		20,219	57,095		19,479	55,441		19,124

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A list of significant equity companies as of December 31, 2015, 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
Cross Timbers Energy, LLC	50
Golden Pass LNG Terminal LLC	18
Karmorneftegaz Holding SARL	33
Marine Well Containment Company LLC	10
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
Downstream
Fujian Refining & Petrochemical Co. Ltd.	25
Saudi Aramco Mobil Refinery Company Ltd.	50
Chemical
Al-Jubail Petrochemical Company	50
Infineum Holdings B.V.	50
Infineum Italia s.r.l.	50
Infineum USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

8. Investments, Advances and Long-Term Receivables

			Dec. 31,	Dec. 31,
			2015	2014
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,337	20,017
	Advances		9,110	9,818
		Total equity company investments and advances	29,447	29,835
Companies carried at cost or less and stock investments carried at fair value			274	526
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $3,040 million and $2,662 million		4,524	4,878
		Total	34,245	35,239

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Property, Plant and Equipment and Asset Retirement Obligations

		December 31, 2015		December 31, 2014
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,821	203,822	347,170	205,308
Downstream		50,742	21,330	53,327	22,639
Chemical		32,481	16,247	30,717	14,918
Other		16,293	10,206	15,575	9,803
	Total	447,337	251,605	446,789	252,668

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

The Corporation periodically reviews the estimated asset service life of its property, plant and equipment. Effective January 1, 2016, the Corporation revised the estimated asset service life of its investments in process equipment in the Chemical segment to 25 years. This revision will not have a material impact on the Corporation’s financial statements.

Accumulated depreciation and depletion totaled $195,732 million at the end of 2015 and $194,121 million at the end of 2014. Interest capitalized in 2015, 2014 and 2013 was $482 million, $344 million and $309 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, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value.

Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on 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 future settlement dates of such obligations.

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

		2015	2014
		(millions of dollars)
Beginning balance		13,424	12,988
	Accretion expense and other provisions	775	871
	Reduction due to property sales	(208)	(151)
	Payments made	(928)	(724)
	Liabilities incurred	283	122
	Foreign currency translation	(931)	(908)
	Revisions	1,289	1,226
Ending balance		13,704	13,424

76

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 completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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 government payment 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 costs.

Change in capitalized suspended exploratory well costs:

			2015	2014	2013
			(millions of dollars)
Balance beginning at January 1			3,587	2,707	2,679
	Additions pending the determination of proved reserves		847	1,095	293
	Charged to expense		(5)	(28)	(52)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(43)	(160)	(107)
	Divestments/Other		(14)	(27)	(106)
Ending balance at December 31			4,372	3,587	2,707
Ending balance attributed to equity companies included above			696	645	13

Period end capitalized suspended exploratory well costs:

			2015	2014	2013
			(millions of dollars)
Capitalized for a period of one year or less			847	1,095	293
	Capitalized for a period of between one and five years		2,386	1,659	1,705
	Capitalized for a period of between five and ten years		826	544	470
	Capitalized for a period of greater than ten years		313	289	239
Capitalized for a period greater than one year - subtotal			3,525	2,492	2,414
		Total	4,372	3,587	2,707

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months, which includes the Rosneft joint venture exploration activity (refer to the relevant portion of Note 7).

			2015	2014	2013
Number of projects with first capitalized well drilled in the preceding 12 months			4	8	8
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		55	53	50
		Total	59	61	58

Of the 55 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2015, 18 projects have drilling in the preceding 12 months or exploratory activity either planned in the next two years or subject to sanctions. The remaining 37 projects are those with completed exploratory activity progressing toward development.

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The table below provides additional detail for those 37 projects, which total $1,154 million.

			Years
		Dec. 31,	Wells
Country/Project		2015	Drilled	Comment
	(millions of dollars)
Angola
- Kaombo Split Hub Phase 2		20	2005 - 2006	Evaluating development plan to tie into planned production facilities.
- Perpetua-Zinia-Acacia		15	2008 - 2009	Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure.
Australia
- East Pilchard		7	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		11	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		34	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Canada
- Horn River		241	2009 - 2012	Evaluating development alternatives to tie into planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		29	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.
- Kalamkas		18	2006 - 2009	Evaluating development alternatives, while continuing discussions with the
				government regarding development plan.
Malaysia
- 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.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Pegi		32	2009	Awaiting capacity in existing/planned infrastructure.
- Satellite Field		12	2013	Evaluating development plan to tie into planned production facilities.
Development Phase 2
- Other (4 projects)		14	2002	Evaluating and pursuing development of several additional discoveries.
Norway
- Gamma		13	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		15	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		25	2008 - 2014	Evaluating development plans, including potential for tieback to existing production
				facilities.
Papua New Guinea
- Juha		28	2007	Progressing development plans to tie into existing 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
- Hadrian North		209	2010 - 2013	Evaluating development plan to tie into existing production facilities.
- Tip Top		31	2009	Evaluating development concept and requisite facility upgrades.
Total 2015 (37 projects)		1,154

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. Leased Facilities

At December 31, 2015, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $4,877 million as indicated in the table. Estimated related rental income from noncancelable subleases is $32 million.

	Lease Payments Under Minimum Commitments			Related
	Drilling Rigs			Sublease
	and Related			Rental
	Equipment	Other	Total	Income
	(millions of dollars)
2016	827	826	1,653	7
2017	408	595	1,003	6
2018	134	421	555	2
2019	89	255	344	2
2020	77	188	265	2
2021 and beyond	86	971	1,057	13
Total	1,621	3,256	4,877	32

Net rental cost under both cancelable and noncancelable operating leases incurred during 2015, 2014 and 2013 were as follows:

			2015	2014	2013
			(millions of dollars)
Rental cost
	Drilling rigs and related equipment		1,853	1,763	1,424
	Other		2,120	2,314	2,417
		Total	3,973	4,077	3,841
	Less sublease rental income		44	52	44
Net rental cost			3,929	4,025	3,797

12. Earnings Per Share

	2015	2014	2013
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	16,150	32,520	32,580
Weighted average number of common shares outstanding(millions of shares)	4,196	4,282	4,419
Earnings per common share(dollars) (1)	3.85	7.60	7.37
Dividends paid per common share (dollars)	2.88	2.70	2.46

(1)   The earnings per common share and earnings per common share assuming dilution are the same in each period shown.

79

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 techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, excluding capitalized lease obligations, was $18.9 billion and $11.7 billion at December 31, 2015, and 2014, respectively, as compared to recorded book values of $18.7 billion and $11.3 billion at December 31, 2015, and 2014, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $8.0 billion of long-term debt in the first quarter of 2015.

The fair value of long-term debt by hierarchy level at December 31, 2015, is: Level 1 $18,584 million; Level 2 $208 million; and Level 3 $62 million. 

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

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net asset of $21 million at year-end 2015 and a net asset of $75 million at year-end 2014. Assets and liabilities associated with derivatives are usually recorded either in “Other current assets” or “Accounts payable and accrued liabilities.”

The Corporation’s fair value measurement of its derivative instruments use either Level 1 or Level 2 inputs.

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $39 million, $110 million and $(7) million during 2015, 2014 and 2013, respectively. Income statement effects associated with derivatives are usually recorded either in “Sales and other operating revenue” or “Crude oil 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 result of the derivative activities described above.

80

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Long-Term Debt

At December 31, 2015, long-term debt consisted of $19,217 million due in U.S. dollars and $708 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $558 million, which matures within one year and is included in current liabilities. The increase in the book value of long-term debt reflects the Corporation’s issuance of $8.0 billion of long-term debt in the first quarter of 2015. The amounts of long-term debt, including capitalized lease obligations, maturing in each of the four years after December 31, 2016, in millions of dollars, are: 2017 – $2,959; 2018 – $2,967; 2019 – $2,374; and 2020 – $1,602. At December 31, 2015, the Corporation’s unused long-term credit lines were $0.4 billion.

Summarized long-term debt at year-end 2015 and 2014 are shown in the table below:

			2015	2014
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	1,500
	Floating-rate notes due 2017 (1)		750	750
	Floating-rate notes due 2018 (2)		500	-
	1.305% notes due 2018		1,600	-
	1.819% notes due 2019		1,750	1,750
	Floating-rate notes due 2019 (3)		500	500
	1.912% notes due 2020		1,500	-
	2.397% notes due 2022		1,150	-
	Floating-rate notes due 2022 (4)		500	-
	3.176% notes due 2024		1,000	1,000
	2.709% notes due 2025		1,750	-
	3.567% notes due 2045		1,000	-
XTO Energy Inc. (5)
	5.650% senior notes due 2016		-	207
	6.250% senior notes due 2017		465	477
	5.500% senior notes due 2018		377	383
	6.500% senior notes due 2018		463	474
	6.100% senior notes due 2036		198	199
	6.750% senior notes due 2037		307	309
	6.375% senior notes due 2038		235	236
Mobil Producing Nigeria Unlimited (6)
	Variable notes due 2016-2019		101	399
Esso (Thailand) Public Company Ltd.(7)
	Variable notes due 2016-2020		83	121
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2017-2051 (8)			2,611	2,611
Other U.S. dollar obligations (9)			97	104
Other foreign currency obligations			1	9
Capitalized lease obligations(10)			1,238	375
		Total long-term debt	19,925	11,653

(1)   Average effective interest rate of 0.3% in 2015 and 0.3% in 2014.

(2)   Average effective interest rate of 0.4% in 2015.

(3)   Average effective interest rate of 0.5% in 2015 and 0.4% in 2014.

(4)   Average effective interest rate of 0.7% in 2015.

(5)   Includes premiums of $179 million in 2015 and $219 million in 2014.

(6)   Average effective interest rate of 4.6% in 2015 and 4.5% in 2014.

(7)   Average effective interest rate of 2.1% in 2015 and 2.4% in 2014.

(8)   Average effective interest rate of 0.02% in 2015 and 0.03% in 2014.

(9)   Average effective interest rate of 3.8% in 2015 and 4.2% in 2014.

(10) Average imputed interest rate of 9.2% in 2015 and 7.0% in 2014.

81

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 may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions 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 grant and 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. Awards that 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 awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2015, remaining shares available for award under the 2003 Incentive Program were 100million.  

Restricted Stock and Restricted Stock Units. Awards totaling 9,681 thousand, 9,775 thousand, and 9,729 thousand of restricted (nonvested) common stock units were granted in 2015, 2014 and 2013, respectively. Compensation expense for these awards is based on 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 employees from 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. During the 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 vesting 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. Awards 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 occurs 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 plans and 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, 2015.

	2015
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	44,439		81.45
2014 award issued in 2015	9,758		95.20
Vested	(9,945)		79.86
Forfeited	(189)		82.26
Issued and outstanding at December 31	44,063		84.85

Value of restricted stock and units	2015	2014	2013
Grant price (dollars)	81.27	95.20	94.47
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	727	858	843
Units settled in cash	60	73	76
Total value	787	931	919

As of December 31, 2015, there was $2,222 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted stock units was $855 million, $831 million and $854 million for 2015, 2014 and 2013, respectively. The income tax benefit recognized in income related to this compensation expense was $78 million, $76 million and $78 million for the same periods, respectively. The fair value of shares and units vested in 2015, 2014 and 2013 was $808 million, $946 million and $1,040 million, respectively. Cash payments of $64 million, $73 million and $67 million for vested restricted stock units settled in cash were made in 2015, 2014 and 2013, respectively.

82

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Litigation and Other Contingencies

Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount 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 amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters as well as other matters which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the 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, 2015, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure.

						Dec. 31, 2015
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			98		35	133
	Other			2,539		4,553	7,092
		Total		2,637		4,588	7,225
(1) ExxonMobil share.

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

	Payments Due by Period
		2017-	2021 and
	2016	2020	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	133	493		310	936

(1)   Undiscounted obligations of $936 million mainly pertain to pipeline throughput agreements and include $411 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $144 million, totaled $792 million.

83

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 National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an 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 for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID). The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. On October 9, 2014, the ICSID Tribunal issued its final award finding in favor of the ExxonMobil affiliates and awarding $1.6 billion as of the date of expropriation, June 27, 2007, and interest from that date at 3.25% compounded annually until the date of payment in full. The Tribunal also noted that one of the Cerro Negro Project agreements provides a mechanism to prevent double recovery between the ICSID award and all or part of an earlier award of $908 million to an ExxonMobil affiliate, Mobil Cerro Negro, Ltd., against PdVSA and a PdVSA affiliate, PdVSA CN, in an arbitration under the rules of the International Chamber of Commerce.

On June 12, 2015, the Tribunal rejected in its entirety Venezuela’s October 23, 2014, application to revise the ICSID award. The Tribunal also lifted the associated stay of enforcement that had been entered upon the filing of the application to revise.

Still pending is Venezuela’s February 2, 2015, application to ICSID seeking annulment of the ICSID award. That application alleges that, in issuing the ICSID award, the Tribunal exceeded its powers, failed to state reasons on which the ICSID award was based, and departed from a fundamental rule of procedure. A separate stay of the ICSID award was entered following the filing of the annulment application. On July 7, 2015, the ICSID Committee considering the annulment application heard arguments from the parties on whether to lift the stay of the award associated with that application. On July 28, 2015, the Committee issued an order that would lift the stay of enforcement unless, within 30 days, Venezuela delivered a commitment to pay the award if the application to annul is denied. On September 17, 2015, the Committee ruled that Venezuela had complied with the requirement to submit a written commitment to pay the award and so left the stay of enforcement in place. A hearing on Venezuela’s application for annulment, previously scheduled for January 25-27, 2016, has been rescheduled for March 8-9, 2016.  

The United States District Court for the Southern District of New York entered judgment on the ICSID award on October 10, 2014. Motions filed by Venezuela to vacate that judgment on procedural grounds and to modify the judgment by reducing the rate of interest to be paid on the ICSID award from the entry of the court’s judgment, until the date of payment, were denied on February 13, 2015, and March 4, 2015, respectively. On March 9, 2015, Venezuela filed a notice of appeal of the court’s actions on the two motions. Oral arguments on this appeal were held before the United States Court of Appeals for the Second Circuit on January 7, 2016.

The District Court’s judgment on the ICSID award is currently stayed until such time as ICSID’s stay of the award entered following Venezuela’s filing of its application to annul has been lifted. The net impact of these matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material 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 Corporation (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 percent 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 of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors' position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Nigerian 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 award. The Contractors appealed that judgment to the Court of Appeal, Abuja Judicial Division. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in order to preserve their ability to seek enforcement of the PSC in the courts if necessary. In October 2014, the Contractors filed suit in the United States District Court for the Southern District of New York to enforce, if necessary, the arbitration award against NNPC assets residing within that jurisdiction. NNPC has moved to dismiss the lawsuit. Proceedings in the Southern District of New York are currently stayed. At this time, the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation's operations or financial condition. 

84

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 Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.25	4.00	3.60	3.10	4.25	4.00
	Long-term rate of compensation increase	5.75	5.75	4.80	5.30	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	20,529	17,304	30,047	27,357	9,436	7,868
	Service cost	864	677	689	590	170	140
	Interest cost	785	807	850	1,138	346	383
	Actuarial loss/(gain)	(545)	3,192	(1,517)	4,929	(617)	1,522
	Benefits paid (1) (2)	(2,050)	(1,427)	(1,287)	(1,366)	(482)	(525)
	Foreign exchange rate changes	-	-	(3,242)	(2,540)	(106)	(48)
	Amendments, divestments and other	-	(24)	(423)	(61)	(465)	96
Benefit obligation at December 31		19,583	20,529	25,117	30,047	8,282	9,436
Accumulated benefit obligation at December 31		15,666	16,385	22,362	26,318	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2015 and 2014, other postretirement benefits paid are net of $15 million and $21 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 discount rate determined by use of a yield curve based on high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For major 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 curves, 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 2017 and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $88 million and the postretirement benefit obligation by $963 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $66 million and the postretirement benefit obligation by $764 million.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Change in plan assets
	Fair value at January 1	12,915	11,190	20,095	19,283	468	620
	Actual return on plan assets	(307)	1,497	918	3,153	-	41
	Foreign exchange rate changes	-	-	(2,109)	(1,738)	-	-
	Company contribution	-	1,476	515	554	42	31
	Benefits paid(1)	(1,623)	(1,248)	(890)	(912)	(96)	(224)
	Other	-	-	(112)	(245)	-	-
Fair value at December 31		10,985	12,915	18,417	20,095	414	468

(1)   Benefit payments for funded plans.

85

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, certain 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 encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

		Pension Benefits
		U.S.		Non-U.S.
		2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(5,782)	(4,590)	(588)	(2,113)
	Unfunded plans	(2,816)	(3,024)	(6,112)	(7,839)
Total		(8,598)	(7,614)	(6,700)	(9,952)

The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status 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 the year in which the changes occur through other comprehensive income.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31  (1)	(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	-	454	302	-	-
	Current liabilities	(311)	(340)	(299)	(325)	(363)	(369)
	Postretirement benefits reserves	(8,287)	(7,274)	(6,855)	(9,929)	(7,505)	(8,599)
Total recorded		(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,138	6,589	6,413	9,642	2,171	2,997
	Prior service cost	21	27	(83)	429	(460)	51
Total recorded in accumulated other
	comprehensive income	6,159	6,616	6,330	10,071	1,711	3,048

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

86

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 return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.

									Other
			Pension Benefits						Postretirement
			U.S.			Non-U.S.			Benefits
			2015	2014	2013	2015	2014	2013	2015	2014	2013
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31	(percent)
	Discount rate		4.00	5.00	4.00	3.10	4.30	3.80	4.00	5.00	4.00
	Long-term rate of return on funded assets		7.00	7.25	7.25	5.90	6.30	6.40	7.00	7.25	7.25
	Long-term rate of compensation increase		5.75	5.75	5.75	5.30	5.40	5.50	5.75	5.75	5.75
Components of net periodic benefit cost			(millions of dollars)
	Service cost		864	677	801	689	590	697	170	140	176
	Interest cost		785	807	749	850	1,138	1,076	346	383	352
	Expected return on plan assets		(830)	(799)	(835)	(1,094)	(1,193)	(1,128)	(28)	(37)	(41)
	Amortization of actuarial loss/(gain)		544	409	646	730	628	852	206	116	228
	Amortization of prior service cost		6	8	7	87	120	117	(24)	14	21
	Net pension enhancement and
	curtailment/settlement cost		499	276	723	22	-	22	-	-	-
Net periodic benefit cost			1,868	1,378	2,091	1,284	1,283	1,636	670	616	736
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)		592	2,494	(1,302)	(1,375)	2,969	(1,938)	(589)	1,518	(1,290)
	Amortization of actuarial (loss)/gain		(1,043)	(685)	(1,369)	(752)	(628)	(874)	(206)	(116)	(228)
	Prior service cost/(credit)		-	(25)	-	(401)	(70)	30	(535)	-	-
	Amortization of prior service (cost)/credit		(6)	(8)	(7)	(87)	(120)	(117)	24	(14)	(21)
	Foreign exchange rate changes		-	-	-	(1,126)	(688)	(155)	(31)	(8)	(10)
Total recorded in other comprehensive income			(457)	1,776	(2,678)	(3,741)	1,463	(3,054)	(1,337)	1,380	(1,549)
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax		1,411	3,154	(587)	(2,457)	2,746	(1,418)	(667)	1,996	(813)

Costs for defined contribution plans were $405 million, $393 million and $392 million in 2015, 2014 and 2013, respectively.

87

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
		2015	2014	2013
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	457	(1,776)	2,678
	Non-U.S. pension	3,741	(1,463)	3,054
	Other postretirement benefits	1,337	(1,380)	1,549
Total (charge)/credit to other comprehensive income, before tax		5,535	(4,619)	7,281
(Charge)/credit to income tax (see Note 4)		(1,810)	1,549	(2,336)
(Charge)/credit to investment in equity companies		81	(81)	49
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	3,806	(3,151)	4,994
Charge/(credit) to equity of noncontrolling interests		(202)	85	(279)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		3,604	(3,066)	4,715

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed 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 and the major non-U.S. plans is 40 percent equity securities and 60 percent debt securities. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on 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 risk or credit quality of an investment.

88

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The 2015 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, 2015, Using:							at December 31, 2015, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	1,992	(1)	-		1,992		-		3,179	(1)	-		3,179
		Non-U.S.		-	1,775	(1)	-		1,775		179	(2)	3,429	(1)	-		3,608
	Private equity			-	-		595	(3)	595		-		-		581	(3)	581
	Debt securities
		Corporate		-	4,161	(4)	-		4,161		-		2,561	(4)	-		2,561
		Government		-	2,394	(4)	-		2,394		243	(5)	8,125	(4)	-		8,368
		Asset-backed		-	3	(4)	-		3		-		71	(4)	-		71
	Real estate funds			-	-		-		-		-		-		-		-
	Cash			-	50	(6)	-		50		11		12	(7)	-		23
Total at fair value				-	10,375		595		10,970		433		17,377		581		18,391
	Insurance contracts
		at contract value							15								26
Total plan assets									10,985								18,417

(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 Level 2 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 Public 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 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 input.

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

89

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Other Postretirement
				Fair Value Measurement
			at December 31, 2015, Using:
				Level 1	Level 2		Level 3	Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	96	(1)	-	96
		Non-U.S.		-	67	(1)	-	67
	Private equity			-	-		-	-
	Debt securities
		Corporate		-	79	(2)	-	79
		Government		-	170	(2)	-	170
		Asset-backed		-	1	(2)	-	1
	Cash			-	1		-	1
Total at fair value				-	414		-	414

(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 Level 2 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 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 2015 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2015
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	562	535	57	2
Net realized gains/(losses)	1	26	(5)	-
Net unrealized gains/(losses)	106	64	-	-
Net purchases/(sales)	(74)	(44)	(52)	(2)
Fair value at December 31	595	581	-	-

90

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The 2014 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, 2014, Using:							at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	2,331	(1)	-		2,331		-		3,284	(1)	-		3,284
		Non-U.S.		-	2,144	(1)	-		2,144		229	(2)	3,776	(1)	-		4,005
	Private equity			-	-		562	(3)	562		-		-		535	(3)	535
	Debt securities
		Corporate		-	4,841	(4)	-		4,841		-		2,686	(4)	-		2,686
		Government		-	2,890	(4)	-		2,890		249	(5)	9,050	(4)	-		9,299
		Asset-backed		-	5	(4)	-		5		-		146	(4)	-		146
	Real estate funds			-	-		-		-		-		-		57	(6)	57
	Cash			-	131	(7)	-		131		25		31	(8)	-		56
Total at fair value				-	12,342		562		12,904		503		18,973		592		20,068
	Insurance contracts
		at contract value							11								27
Total plan assets									12,915								20,095

(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 Level 2 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 Public 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 input.

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

91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Other Postretirement
			Fair Value Measurement
			at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	106	(1)	-		106
		Non-U.S.		-	75	(1)	-		75
	Private equity			-	-		2	(2)	2
	Debt securities
		Corporate		-	103	(3)	-		103
		Government		-	171	(3)	-		171
		Asset-backed		-	9	(3)	-		9
	Cash			-	2		-		2
Total at fair value				-	466		2		468

(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 Level 2 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 Public 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 2014 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2014
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	523	502	136	9
Net realized gains/(losses)	2	23	(17)	-
Net unrealized gains/(losses)	89	31	8	-
Net purchases/(sales)	(52)	(21)	(70)	(7)
Fair value at December 31	562	535	57	2

92

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.
			2015	2014		2015	2014
		(millions of dollars)
For funded  pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		16,767	17,505		1,827	5,031
	Accumulated benefit obligation		13,913	14,493		1,373	4,590
	Fair value of plan assets		10,985	12,915		1,299	3,890
For unfunded  pension plans:
	Projected benefit obligation		2,816	3,024		6,112	7,839
	Accumulated benefit obligation		1,753	1,892		5,290	6,573

					Other
			Pension Benefits		Postretirement
			U.S.	Non-U.S.	Benefits
		(millions of dollars)
Estimated 2016 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain)  (1)		930	543		152
	Prior service cost  (2)		6	55		(30)

(1)   The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service 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 other postretirement benefit plans.

		Pension Benefits		Other Postretirement Benefits
					Medicare
		U.S.	Non-U.S.	Gross	Subsidy Receipt
		(millions of dollars)
Contributions expected in 2016		2,000	525	-		-
Benefit payments expected in:
	2016	1,548	1,145	457		24
	2017	1,491	1,128	470		25
	2018	1,411	1,178	481		26
	2019	1,382	1,193	490		28
	2020	1,342	1,227	497		29
	2021 - 2025	6,594	6,359	2,518		170

18. Disclosures about Segments and Related Information

The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.

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

Earnings after income tax include transfers at estimated market prices.

93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $100 million and $129 million in 2015 and 2014, respectively. For 2013, non-debt-related interest expense was a net credit of $123 million, primarily reflecting the effect of credits from the favorable resolution of prior year tax positions.

													Corporate
	Upstream				Downstream				Chemical					and	Corporate
	U.S.		Non-U.S.		U.S.		Non-U.S.		U.S.		Non-U.S.		Financing			Total
		(millions of dollars)
As of December 31, 2015
Earnings after income tax		(1,079)		8,180		1,901		4,656		2,386		2,032		(1,926)		16,150
Earnings of equity companies included above		226		5,831		170		444		144		1,235		(406)		7,644
Sales and other operating revenue (1)		8,241		15,812		73,063		134,230		10,880		17,254		8		259,488
Intersegment revenue		4,344		20,839		12,440		22,166		7,442		5,168		274		-
Depreciation and depletion expense		5,301		9,227		664		1,003		375		654		824		18,048
Interest revenue		-		-		-		-		-		-		46		46
Interest expense		26		27		8		4		-		1		245		311
Income taxes		(879)		4,703		866		1,325		646		633		(1,879)		5,415
Additions to property, plant and equipment		6,915		14,561		916		1,477		1,865		629		1,112		27,475
Investments in equity companies		5,160		10,980		95		1,179		125		3,025		(227)		20,337
Total assets		93,648		155,316		16,498		29,808		10,174		18,236		13,078		336,758
As of December 31, 2014
Earnings after income tax		5,197		22,351		1,618		1,427		2,804		1,511		(2,388)		32,520
Earnings of equity companies included above		1,235		10,859		29		82		186		1,377		(445)		13,323
Sales and other operating revenue (1)		14,826		22,336		118,771		199,976		15,115		23,063		18		394,105
Intersegment revenue		7,723		38,846		17,281		44,231		10,117		8,098		274		-
Depreciation and depletion expense		5,139		8,523		654		1,228		370		645		738		17,297
Interest revenue		-		-		-		-		-		-		75		75
Interest expense		40		17		6		4		-		-		219		286
Income taxes		1,300		15,165		610		968		1,032		358		(1,418)		18,015
Additions to property, plant and equipment		9,098		19,225		1,050		1,356		1,564		564		1,399		34,256
Investments in equity companies		5,089		10,877		69		1,006		258		3,026		(308)		20,017
Total assets		92,555		161,033		18,371		33,299		8,798		18,449		16,988		349,493
As of December 31, 2013
Earnings after income tax		4,191		22,650		2,199		1,250		2,755		1,073		(1,538)		32,580
Earnings of equity companies included above		1,576		11,627		(460)		22		189		1,422		(449)		13,927
Sales and other operating revenue (1)		13,712		25,349		123,802		218,904		15,295		23,753		21		420,836
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		17,182
Interest revenue		-		-		-		-		-		-		87		87
Interest expense		30		26		7		8		1		-		(63)		9
Income taxes		2,197		21,554		721		481		989		363		(2,042)		24,263
Additions to property, plant and equipment		7,480		26,075		616		1,072		840		272		1,386		37,741
Investments in equity companies		4,975		9,740		62		1,749		217		3,103		(227)		19,619
Total assets		88,698		157,465		19,261		40,661		7,816		19,659		13,248		346,808

(1)  Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

94

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Geographic
Sales and other operating revenue (1)		2015	2014	2013
		(millions of dollars)
United States		92,184	148,713	152,820
Non-U.S.		167,304	245,392	268,016
	Total	259,488	394,105	420,836
Significant non-U.S. revenue sources include:
	United Kingdom	23,651	31,346	34,061
	Canada	22,876	36,072	35,924
	Italy	13,795	18,880	19,273
	Belgium	13,154	20,953	20,973
	France	11,808	17,639	18,444
	Singapore	10,790	15,407	15,623
	Germany	10,045	14,816	15,701

(1)  Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

Long-lived assets		2015	2014	2013
		(millions of dollars)
United States		107,039	104,000	98,271
Non-U.S.		144,566	148,668	145,379
	Total	251,605	252,668	243,650
Significant non-U.S. long-lived assets include:
	Canada	39,775	43,858	41,522
	Australia	15,894	15,328	14,258
	Nigeria	12,222	12,265	12,343
	Kazakhstan	9,705	9,138	8,530
	Singapore	9,681	9,620	9,570
	Angola	8,777	9,057	8,262
	Papua New Guinea	5,985	6,099	5,768

95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19. Income, Sales-Based and Other Taxes

						2015				2014				2013
				U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total
								(millions of dollars)
Income tax expense
	Federal and non-U.S.
		Current		-		7,126	7,126	1,456		14,755	16,211	1,073		22,115	23,188
		Deferred - net		(1,166)		(571)	(1,737)	900		1,398	2,298	(116)		757	641
	U.S. tax on non-U.S. operations			38		-	38	5		-	5	37		-	37
			Total federal and non-U.S.	(1,128)		6,555	5,427	2,361		16,153	18,514	994		22,872	23,866
	State (1)			(12)		-	(12)	(499)		-	(499)	397		-	397
			Total income tax expense	(1,140)		6,555	5,415	1,862		16,153	18,015	1,391		22,872	24,263
Sales-based taxes				6,402		16,276	22,678	6,310		23,032	29,342	5,992		24,597	30,589
All other taxes and duties
	Other taxes and duties			162		27,103	27,265	378		31,908	32,286	955		32,275	33,230
	Included in production and
		manufacturing expenses		1,157		828	1,985	1,454		1,179	2,633	1,318		1,182	2,500
	Included in SG&A expenses			150		390	540	155		441	596	150		516	666
		Total other taxes and duties		1,469		28,321	29,790	1,987		33,528	35,515	2,423		33,973	36,396
			Total	6,731		51,152	57,883	10,159		72,713	82,872	9,806		81,442	91,248

(1)   In 2014, state taxes included a favorable adjustment of deferred taxes of approximately $830 million.

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include a net charge of $177 million in 2015 and net credits of $40 million in 2014 and $310 million in 2013 for the 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 2015, 2014 and 2013 is as follows:

			2015	2014	2013
			(millions of dollars)
Income before income taxes
	United States		147	9,080	9,746
	Non-U.S.		21,819	42,550	47,965
		Total	21,966	51,630	57,711
Theoretical tax			7,688	18,071	20,199
Effect of equity method of accounting			(2,675)	(4,663)	(4,874)
Non-U.S. taxes in excess of theoretical U.S. tax			1,415	5,442	10,528
U.S. tax on non-U.S. operations			38	5	37
State taxes, net of federal tax benefit			(8)	(324)	258
Other			(1,043)	(516)	(1,885)
		Total income tax expense	5,415	18,015	24,263
Effective tax rate calculation
Income taxes			5,415	18,015	24,263
ExxonMobil share of equity company income taxes			3,011	5,678	6,061
		Total income taxes	8,426	23,693	30,324
Net income including noncontrolling interests			16,551	33,615	33,448
		Total income before taxes	24,977	57,308	63,772
Effective income tax rate			34%	41%	48%

96

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 purposes and such amounts recognized for tax purposes.

Deferred tax liabilities/(assets) are comprised of the following at December 31:

Tax effects of temporary differences for:		2015	2014
		(millions of dollars)
Property, plant and equipment		49,409	51,643
Other liabilities		4,613	4,359
	Total deferred tax liabilities	54,022	56,002
Pension and other postretirement benefits		(6,286)	(8,140)
Asset retirement obligations		(6,277)	(6,162)
Tax loss carryforwards		(4,983)	(4,099)
Other assets		(5,592)	(6,446)
	Total deferred tax assets	(23,138)	(24,847)
Asset valuation allowances		1,730	2,570
	Net deferred tax liabilities	32,614	33,725

In 2015, asset valuation allowances of $1,730 million decreased by $840 million and included net provisions of $681 million and effects of foreign currency translation of $159 million. 

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

Balance sheet classification		2015	2014
		(millions of dollars)
Other current assets		(1,329)	(2,001)
Other assets, including intangibles, net		(3,421)	(3,955)
Accounts payable and accrued liabilities		546	451
Deferred income tax liabilities		36,818	39,230
	Net deferred tax liabilities	32,614	33,725

The Corporation had $51 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. that were retained to fund prior and future capital project expenditures. Deferred taxes have not been recorded for potential future tax obligations as these earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2015, it is not practical to estimate the unrecognized deferred tax liability associated with these earnings given the future availability of foreign tax credits and uncertainties about the timing of potential remittances.

97

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Unrecognized Tax Benefits. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits:

Gross unrecognized tax benefits		2015	2014	2013
		(millions of dollars)
Balance at January 1		8,986	7,838	7,663
	Additions based on current year's tax positions	903	1,454	1,460
	Additions for prior years' tax positions	496	448	464
	Reductions for prior years' tax positions	(190)	(532)	(249)
	Reductions due to lapse of the statute of limitations	(4)	(117)	(588)
	Settlements with tax authorities	(725)	(43)	(849)
	Foreign exchange effects/other	(70)	(62)	(63)
Balance at December 31		9,396	8,986	7,838

The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2015, 2014 and 2013 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income.

Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. In the United States, the Corporation has various U.S. federal income tax positions at issue with the Internal Revenue Service for tax years 2006-2011. Unfavorable resolution of these issues would not have a materially adverse effect on the Corporation’s net income or liquidity. The Internal Revenue Service has not completed its audit of tax years after 2011.

It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent in the next 12 months, with no material impact on the Corporation’s net income.

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

Country of Operation	Open Tax Years
Abu Dhabi	2012 - 2015
Angola	2009 - 2015
Australia	2005, 2008 - 2015
Canada	2008 - 2015
Equatorial Guinea	2007 - 2015
Malaysia	2009 - 2015
Nigeria	2005 - 2015
Norway	2007 - 2015
Qatar	2009 - 2015
Russia	2012 - 2015
United Kingdom	2011 - 2015
United States	2006 - 2015

The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.

The Corporation incurred $39 million and $42 million in interest expense on income tax reserves in 2015 and 2014, respectively. 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 year tax positions. The related interest payable balances were $223 million and $205 million at December 31, 2015, and 2014, respectively.

98

SUPPLEMENTALINFORMATIONONOILANDGASEXPLORATIONANDPRODUCTIONACTIVITIES(unaudited)

The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $831 million in 2015, $3,223 million in 2014, and $886 million in 2013. Oil sands mining operations are included in the results of operations in 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	Total
			(millions of dollars)
Consolidated Subsidiaries
2015 - Revenue
		Sales to third parties	4,830		1,756	3,933	1,275	2,651	1,408	15,853
		Transfers	2,557		2,858	2,024	8,135	4,490	608	20,672
			7,387		4,614	5,957	9,410	7,141	2,016	36,525
	Production costs excluding taxes		4,252		3,690	2,232	1,993	1,562	527	14,256
	Exploration expenses		182		473	187	319	254	108	1,523
	Depreciation and depletion		5,054		1,315	1,641	3,874	1,569	392	13,845
	Taxes other than income		630		111	200	734	706	171	2,552
	Related income tax		(976)		(79)	807	1,556	2,117	238	3,663
	Results of producing activities for consolidated
		subsidiaries	(1,755)		(896)	890	934	933	580	686
Equity Companies
2015 - Revenue
		Sales to third parties	608		-	2,723	-	11,174	-	14,505
		Transfers	459		-	31	-	379	-	869
			1,067		-	2,754	-	11,553	-	15,374
	Production costs excluding taxes		554		-	565	-	422	-	1,541
	Exploration expenses		12		-	21	-	18	-	51
	Depreciation and depletion		271		-	146	-	457	-	874
	Taxes other than income		47		-	1,258	-	3,197	-	4,502
	Related income tax		-		-	263	-	2,559	-	2,822
	Results of producing activities for equity companies		183		-	501	-	4,900	-	5,584
Total results of operations			(1,572)		(896)	1,391	934	5,833	580	6,270

99

				Canada/
			United	South				Australia/
Results of Operations			States	America	Europe	Africa	Asia		Oceania	Total
			(millions of dollars)
Consolidated Subsidiaries
2014 - Revenue
		Sales to third parties	9,453	2,841	4,608	1,943	4,383		1,374	24,602
		Transfers	5,554	5,417	5,206	14,884	7,534		1,553	40,148
			15,007	8,258	9,814	16,827	11,917		2,927	64,750
	Production costs excluding taxes		4,637	4,251	3,117	2,248	1,568		583	16,404
	Exploration expenses		231	363	274	427	287		87	1,669
	Depreciation and depletion		4,877	1,193	1,929	3,387	1,242		454	13,082
	Taxes other than income		1,116	160	412	1,539	1,542		399	5,168
	Related income tax		1,208	524	2,954	5,515	4,882		435	15,518
	Results of producing activities for consolidated
		subsidiaries	2,938	1,767	1,128	3,711	2,396		969	12,909
Equity Companies
2014 - Revenue
		Sales to third parties	1,239	-	4,923	-	20,028		-	26,190
		Transfers	924	-	63	-	685		-	1,672
			2,163	-	4,986	-	20,713		-	27,862
	Production costs excluding taxes		620	-	602	-	548		-	1,770
	Exploration expenses		61	-	22	-	219		-	302
	Depreciation and depletion		253	-	195	-	383		-	831
	Taxes other than income		57	-	2,650	-	5,184		-	7,891
	Related income tax		-	-	553	-	5,099		-	5,652
	Results of producing activities for equity companies		1,172	-	964	-	9,280		-	11,416
Total results of operations			4,110	1,767	2,092	3,711	11,676		969	24,325
Consolidated Subsidiaries
2013 - Revenue
		Sales to third parties	8,371	2,252	5,649	3,079	5,427		730	25,508
		Transfers	6,505	5,666	5,654	15,738	8,936		1,405	43,904
			14,876	7,918	11,303	18,817	14,363		2,135	69,412
	Production costs excluding taxes		4,191	3,965	2,859	2,396	1,763		654	15,828
	Exploration expenses		394	386	245	288	571		92	1,976
	Depreciation and depletion		4,926	989	1,881	3,269	1,680		334	13,079
	Taxes other than income		1,566	94	474	1,583	1,794		427	5,938
	Related income tax		1,788	542	4,124	6,841	5,709		202	19,206
	Results of producing activities for consolidated
		subsidiaries	2,011	1,942	1,720	4,440	2,846		426	13,385
Equity Companies
2013 - Revenue
		Sales to third parties	1,320	-	6,768	-	21,463		-	29,551
		Transfers	1,034	-	64	-	6,091		-	7,189
			2,354	-	6,832	-	27,554		-	36,740
	Production costs excluding taxes		551	-	459	-	660		-	1,670
	Exploration expenses		19	-	15	-	426		-	460
	Depreciation and depletion		207	-	169	-	955		-	1,331
	Taxes other than income		51	-	3,992	-	7,352		-	11,395
	Related income tax		-	-	832	-	8,482		-	9,314
	Results of producing activities for equity companies		1,526	-	1,365	-	9,679		-	12,570
Total results of operations			3,537	1,942	3,085	4,440	12,525		426	25,955

100

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $14,685 million less at year-end 2015 and $12,856 million less at year-end 2014 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 costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations are included in the capitalized costs in accordance with Financial Accounting Standards Board rules.

					Canada/
				United	South				Australia/
Capitalized Costs				States	America	Europe	Africa	Asia		Oceania	Total
				(millions of dollars)
Consolidated Subsidiaries
As of December 31, 2015
	Property (acreage) costs		- Proved	15,989	2,202	143	873	1,648		741	21,596
			- Unproved	23,071	4,014	44	367	409		116	28,021
		Total property costs		39,060	6,216	187	1,240	2,057		857	49,617
	Producing assets			84,270	38,108	36,262	49,621	32,359		9,414	250,034
	Incomplete construction			6,980	5,708	1,928	4,395	8,620		4,564	32,195
		Total capitalized costs		130,310	50,032	38,377	55,256	43,036		14,835	331,846
	Accumulated depreciation and depletion			46,864	13,873	29,747	31,579	16,073		4,573	142,709
	Net capitalized costs for consolidated subsidiaries			83,446	36,159	8,630	23,677	26,963		10,262	189,137
Equity Companies
As of December 31, 2015
	Property (acreage) costs		- Proved	78	-	4	-	-		-	82
			- Unproved	14	-	-	-	59		-	73
		Total property costs		92	-	4	-	59		-	155
	Producing assets			6,181	-	5,089	-	8,563		-	19,833
	Incomplete construction			194	-	77	-	3,727		-	3,998
		Total capitalized costs		6,467	-	5,170	-	12,349		-	23,986
	Accumulated depreciation and depletion			2,122	-	3,916	-	5,563		-	11,601
	Net capitalized costs for equity companies			4,345	-	1,254	-	6,786		-	12,385
Consolidated Subsidiaries
As of December 31, 2014
	Property (acreage) costs		- Proved	14,664	2,598	161	876	1,660		808	20,767
			- Unproved	24,062	4,824	74	615	601		136	30,312
		Total property costs		38,726	7,422	235	1,491	2,261		944	51,079
	Producing assets			79,138	32,635	39,996	44,700	30,219		10,051	236,739
	Incomplete construction			7,051	15,344	2,114	6,075	10,163		4,621	45,368
		Total capitalized costs		124,915	55,401	42,345	52,266	42,643		15,616	333,186
	Accumulated depreciation and depletion			43,031	15,197	32,608	27,995	17,273		4,630	140,734
	Net capitalized costs for consolidated subsidiaries			81,884	40,204	9,737	24,271	25,370		10,986	192,452
Equity Companies
As of December 31, 2014
	Property (acreage) costs		- Proved	78	-	4	-	-		-	82
			- Unproved	35	-	-	-	59		-	94
		Total property costs		113	-	4	-	59		-	176
	Producing assets			5,538	-	5,309	-	8,500		-	19,347
	Incomplete construction			473	-	251	-	2,972		-	3,696
		Total capitalized costs		6,124	-	5,564	-	11,531		-	23,219
	Accumulated depreciation and depletion			1,872	-	4,205	-	5,095		-	11,172
	Net capitalized costs for equity companies			4,252	-	1,359	-	6,436		-	12,047

101

Oil and Gas Exploration and Production Costs (continued)

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2015 were $21,887 million, down $7,228 million from 2014, due primarily to lower development costs and property acquisition costs. In 2014 costs were $29,115 million, down $4,508 million from 2013, due primarily to lower property acquisition costs and development costs. Total equity company costs incurred in 2015 were $1,464 million, down $1,213 million from 2014, due primarily to exploration costs.

						Canada/
Costs Incurred in Property Acquisitions,					United	South				Australia/
Exploration and Development Activities					States	America	Europe	Africa	Asia		Oceania	Total
				(millions of dollars)
During 2015
	Consolidated Subsidiaries
		Property acquisition costs	- Proved		6	-	-	-	31		-	37
			- Unproved		305	39	-	93	1		2	440
		Exploration costs			195	621	411	425	405		157	2,214
		Development costs			6,774	3,764	1,439	3,149	3,068		1,002	19,196
		Total costs incurred for consolidated subsidiaries			7,280	4,424	1,850	3,667	3,505		1,161	21,887
	Equity Companies
		Property acquisition costs	- Proved		-	-	-	-	-		-	-
			- Unproved		-	-	-	-	-		-	-
		Exploration costs			9	-	41	-	(19)		-	31
		Development costs			411	-	143	-	879		-	1,433
		Total costs incurred for equity companies			420	-	184	-	860		-	1,464
During 2014
	Consolidated Subsidiaries
		Property acquisition costs	- Proved		80	-	-	-	41		-	121
			- Unproved		1,253	3	19	34	-		-	1,309
		Exploration costs			319	453	458	628	467		121	2,446
		Development costs			7,540	6,877	1,390	4,255	3,321		1,856	25,239
		Total costs incurred for consolidated subsidiaries			9,192	7,333	1,867	4,917	3,829		1,977	29,115
	Equity Companies
		Property acquisition costs	- Proved		-	-	-	-	-		-	-
			- Unproved		-	-	-	-	42		-	42
		Exploration costs			17	-	45	-	964		-	1,026
		Development costs			490	-	233	-	886		-	1,609
		Total costs incurred for equity companies			507	-	278	-	1,892		-	2,677
During 2013
	Consolidated Subsidiaries
		Property acquisition costs	- Proved		93	67	-	-	47		-	207
			- Unproved		533	4,270	-	153	-		4	4,960
		Exploration costs			557	485	277	361	598		111	2,389
		Development costs			6,919	8,527	2,117	3,278	3,493		1,733	26,067
		Total costs incurred for consolidated subsidiaries			8,102	13,349	2,394	3,792	4,138		1,848	33,623
	Equity Companies
		Property acquisition costs	- Proved		2	-	-	-	-		-	2
			- Unproved		-	-	-	-	17		-	17
		Exploration costs			60	-	29	-	494		-	583
		Development costs			720	-	192	-	828		-	1,740
		Total costs incurred for equity companies			782	-	221	-	1,339		-	2,342

102

Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2013, 2014, and 2015.

The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.

In accordance with the Securities and Exchange Commission’s (SEC) rules, the year-end reserves volumes as well as the reserves change categories shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.

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

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.

In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.

Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2015 that were associated with production sharing contract arrangements was 10 percent of liquids, 10 percent of natural gas and 10 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes.

The changes between 2014 year-end proved reserves and 2015 year-end proved reserves primarily reflect extensions and purchases in the United States and Asia, and revisions in the United States and Canada. Due to low natural gas prices during 2015, the Corporation reclassified approximately 4,800 billion cubic feet of natural gas reserves in the United States which no longer meet the SEC definition of proved reserves.

103

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves
									Natural Gas
		Crude Oil								Liquids (1)	Bitumen	Synthetic Oil
		United	Canada/			Australia/					Canada/		Canada/
		States	S. Amer.	Europe	Africa	Asia	Oceania	Total	Worldwide		S. Amer.		S. Amer.	Total
		(millions of barrels)
Net proved developed and
	undeveloped reserves of
	consolidated subsidiaries
January 1, 2013		1,905	270	289	1,293	1,604	163	5,524		1,031	3,560		599	10,714
	Revisions	21	20	13	13	411	3	481		(1)	124		4	608
	Improved recovery	-	-	-	-	-	-	-		-	-		-	-
	Purchases	15	15	-	-	-	-	30		27	-		-	57
	Sales	(18)	-	-	-	-	-	(18)		(6)	-		-	(24)
	Extensions/discoveries	188	-	-	52	262	-	502		39	-		-	541
	Production	(103)	(21)	(57)	(165)	(114)	(11)	(471)		(67)	(54)		(24)	(616)
December 31, 2013		2,008	284	245	1,193	2,163	155	6,048		1,023	3,630		579	11,280
Proportional interest in proved
	reserves of equity companies
January 1, 2013		340	-	28	-	1,260	-	1,628		474	-		-	2,102
	Revisions	12	-	2	-	21	-	35		8	-		-	43
	Improved recovery	-	-	-	-	-	-	-		-	-		-	-
	Purchases	-	-	-	-	-	-	-		-	-		-	-
	Sales	-	-	-	-	-	-	-		-	-		-	-
	Extensions/discoveries	-	-	-	-	-	-	-		-	-		-	-
	Production	(22)	-	(2)	-	(136)	-	(160)		(26)	-		-	(186)
December 31, 2013		330	-	28	-	1,145	-	1,503		456	-		-	1,959
Total liquids proved reserves
	at December 31, 2013	2,338	284	273	1,193	3,308	155	7,551		1,479	3,630		579	13,239
Net proved developed and
	undeveloped reserves of
	consolidated subsidiaries
January 1, 2014		2,008	284	245	1,193	2,163	155	6,048		1,023	3,630		579	11,280
	Revisions	37	23	9	42	42	-	153		59	669		(23)	858
	Improved recovery	-	-	-	-	-	-	-		-	-		-	-
	Purchases	42	-	-	-	-	-	42		11	-		-	53
	Sales	(24)	(11)	-	-	(1)	-	(36)		(14)	-		-	(50)
	Extensions/discoveries	156	5	-	38	35	-	234		79	-		-	313
	Production	(111)	(19)	(55)	(171)	(107)	(14)	(477)		(66)	(66)		(22)	(631)
December 31, 2014		2,108	282	199	1,102	2,132	141	5,964		1,092	4,233		534	11,823
Proportional interest in proved
	reserves of equity companies
January 1, 2014		330	-	28	-	1,145	-	1,503		456	-		-	1,959
	Revisions	19	-	1	-	41	-	61		5	-		-	66
	Improved recovery	-	-	-	-	-	-	-		-	-		-	-
	Purchases	1	-	-	-	-	-	1		-	-		-	1
	Sales	-	-	-	-	-	-	-		-	-		-	-
	Extensions/discoveries	1	-	-	-	-	-	1		-	-		-	1
	Production	(23)	-	(2)	-	(86)	-	(111)		(26)	-		-	(137)
December 31, 2014		328	-	27	-	1,100	-	1,455		435	-		-	1,890
Total liquids proved reserves
	at December 31, 2014	2,436	282	226	1,102	3,232	141	7,419		1,527	4,233		534	13,713

(See footnote on next page)

104

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
									Natural Gas
		Crude Oil								Liquids (1)	Bitumen	Synthetic Oil
		United	Canada/			Australia/					Canada/		Canada/
		States	S. Amer.	Europe	Africa	Asia	Oceania	Total	Worldwide		S. Amer.		S. Amer.	Total
		(millions of barrels)
Net proved developed and
	undeveloped reserves of
	consolidated subsidiaries
January 1, 2015		2,108	282	199	1,102	2,132	141	5,964		1,092	4,233		534	11,823
	Revisions	(150)	(10)	46	48	123	(4)	53		(95)	433		68	459
	Improved recovery	-	-	2	-	-	-	2		-	-		-	2
	Purchases	161	3	1	-	-	-	165		46	-		-	211
	Sales	(9)	-	(1)	-	(2)	-	(12)		(1)	-		-	(13)
	Extensions/discoveries	387	2	-	-	698	-	1,087		101	-		-	1,188
	Production	(119)	(17)	(63)	(187)	(126)	(12)	(524)		(65)	(106)		(21)	(716)
December 31, 2015		2,378	260	184	963	2,825	125	6,735		1,078	4,560		581	12,954
Proportional interest in proved
	reserves of equity companies
January 1, 2015		328	-	27	-	1,100	-	1,455		435	-		-	1,890
	Revisions	(52)	-	(1)	-	65	-	12		5	-		-	17
	Improved recovery	-	-	-	-	-	-	-		-	-		-	-
	Purchases	-	-	-	-	-	-	-		-	-		-	-
	Sales	-	-	-	-	-	-	-		-	-		-	-
	Extensions/discoveries	-	-	-	-	-	-	-		-	-		-	-
	Production	(22)	-	(1)	-	(88)	-	(111)		(26)	-		-	(137)
December 31, 2015		254	-	25	-	1,077	-	1,356		414	-		-	1,770
Total liquids proved reserves
	at December 31, 2015	2,632	260	209	963	3,902	125	8,091		1,492	4,560		581	14,724

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 11 million barrels in 2013, 8 million barrels in 2014 and 7 million barrels in 2015, as well as proved developed reserves of 9 million barrels in 2013, 5 million barrels in 2014 and 4 million barrels in 2015, and in addition, proved undeveloped reserves of 2 million barrels in 2013, 3 million barrels in 2014 and 3 million in 2015, in which there is a 30.4 percent noncontrolling interest.

105

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
												Synthetic
			Crude Oil and Natural Gas Liquids								Bitumen	Oil
				Canada/							Canada/	Canada/
			United	South				Australia/			South	South
			States	Amer. (1)	Europe	Africa	Asia	Oceania	Total	Amer. (2)		Amer. (3)	Total
			(millions of barrels)
Proved developed reserves, as of
	December 31, 2013
		Consolidated subsidiaries	1,469	126	249	945	1,663	105	4,557		1,810	579	6,946
		Equity companies	268	-	27	-	1,292	-	1,587		-	-	1,587
Proved undeveloped reserves, as of
	December 31, 2013
		Consolidated subsidiaries	1,068	177	51	449	638	131	2,514		1,820	-	4,334
		Equity companies	77	-	1	-	294	-	372		-	-	372
Total liquids proved reserves at
	December 31, 2013		2,882	303	328	1,394	3,887	236	9,030		3,630	579	13,239
Proved developed reserves, as of
	December 31, 2014
		Consolidated subsidiaries	1,502	111	205	894	1,615	112	4,439		2,122	534	7,095
		Equity companies	269	-	26	-	1,188	-	1,483		-	-	1,483
Proved undeveloped reserves, as of
	December 31, 2014
		Consolidated subsidiaries	1,234	190	42	401	651	99	2,617		2,111	-	4,728
		Equity companies	75	-	1	-	331	-	407		-	-	407
Total liquids proved reserves at
	December 31, 2014		3,080	301	274	1,295	3,785	211	8,946		4,233	534	13,713
Proved developed reserves, as of
	December 31, 2015
		Consolidated subsidiaries	1,427	101	192	900	1,707	107	4,434		4,108	581	9,123
		Equity companies	228	-	25	-	1,151	-	1,404		-	-	1,404
Proved undeveloped reserves, as of
	December 31, 2015
		Consolidated subsidiaries	1,619	174	34	230	1,239	83	3,379		452	-	3,831
		Equity companies	39	-	-	-	327	-	366		-	-	366
Total liquids proved reserves at
	December 31, 2015		3,313	275	251	1,130	4,424	190	9,583	(4)	4,560	581	14,724

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 62 million barrels in 2013, 46 million barrels in 2014 and 34 million barrels in 2015, as well as proved developed reserves of 55 million barrels in 2013, 36 million barrels in 2014 and 23 million barrels in 2015, and in addition, proved undeveloped reserves of 7 million barrels in 2013, 10 million barrels in 2014 and 11 million barrels in 2015, in which there is a 30.4 percent noncontrolling interest.

(2)   Includes total proved reserves attributable to Imperial Oil Limited of 2,867 million barrels in 2013, 3,274 million barrels in 2014 and 3,515 million barrels in 2015, as well as proved developed reserves of 1,417 million barrels in 2013, 1,635 million barrels in 2014 and 3,063 million barrels in 2015, and in addition, proved undeveloped reserves of 1,450 million barrels in 2013, 1,639 million barrels in 2014 and 452 million barrels in 2015, in which there is a 30.4 percent noncontrolling interest.

(3)   Includes total proved reserves attributable to Imperial Oil Limited of 579 million barrels in 2013, 534 million barrels in 2014 and 581 million barrels in 2015, as well as proved developed reserves of 579 million barrels in 2013, 534 million barrels in 2014 and 581 million barrels in 2015, in which there is a 30.4 percent noncontrolling interest.

(4)   See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2015 Form 10-K.

106

Natural Gas and Oil-Equivalent Proved Reserves
		Natural Gas
			Canada/						Oil-Equivalent
		United	South				Australia/		Total
		States	Amer. (1)	Europe	Africa	Asia	Oceania	Total	All Products (2)
		(billions of cubic feet)							(millions of oil-
									equivalent barrels)
Net proved developed and undeveloped
	reserves of consolidated subsidiaries
January 1, 2013		26,215	925	3,249	929	5,845	7,568	44,731	18,169
	Revisions	79	(56)	61	(22)	364	86	512	693
	Improved recovery	-	-	-	-	-	-	-	-
	Purchases	153	522	-	-	-	-	675	170
	Sales	(106)	(8)	-	-	-	-	(114)	(43)
	Extensions/discoveries	1,083	2	-	-	14	-	1,099	724
	Production	(1,404)	(150)	(500)	(40)	(489)	(139)	(2,722)	(1,069)
December 31, 2013		26,020	1,235	2,810	867	5,734	7,515	44,181	18,644
Proportional interest in proved reserves
	of equity companies
January 1, 2013		155	-	9,535	-	19,670	-	29,360	6,995
	Revisions	135	-	58	-	9	-	202	77
	Improved recovery	-	-	-	-	-	-	-	-
	Purchases	-	-	-	-	-	-	-	-
	Sales	-	-	-	-	-	-	-	-
	Extensions/discoveries	1	-	8	-	-	-	9	2
	Production	(10)	-	(717)	-	(1,165)	-	(1,892)	(502)
December 31, 2013		281	-	8,884	-	18,514	-	27,679	6,572
Total proved reserves at December 31, 2013		26,301	1,235	11,694	867	24,248	7,515	71,860	25,216
Net proved developed and undeveloped
	reserves of consolidated subsidiaries
January 1, 2014		26,020	1,235	2,810	867	5,734	7,515	44,181	18,644
	Revisions	49	80	49	(21)	173	(38)	292	906
	Improved recovery	-	-	-	-	-	-	-	-
	Purchases	60	-	-	-	-	-	60	63
	Sales	(314)	(48)	-	-	(3)	-	(365)	(111)
	Extensions/discoveries	1,518	91	-	7	4	-	1,620	583
	Production	(1,346)	(132)	(476)	(42)	(448)	(201)	(2,645)	(1,072)
December 31, 2014		25,987	1,226	2,383	811	5,460	7,276	43,143	19,013
Proportional interest in proved reserves
	of equity companies
January 1, 2014		281	-	8,884	-	18,514	-	27,679	6,572
	Revisions	5	-	117	-	110	-	232	105
	Improved recovery	-	-	-	-	-	-	-	-
	Purchases	-	-	-	-	-	-	-	1
	Sales	-	-	-	-	-	-	-	-
	Extensions/discoveries	1	-	-	-	-	-	1	1
	Production	(15)	-	(583)	-	(1,119)	-	(1,717)	(423)
December 31, 2014		272	-	8,418	-	17,505	-	26,195	6,256
Total proved reserves at December 31, 2014		26,259	1,226	10,801	811	22,965	7,276	69,338	25,269

(See footnotes on next page)

107

Natural Gas and Oil-Equivalent Proved Reserves (continued)
		Natural Gas
			Canada/						Oil-Equivalent
		United	South				Australia/		Total
		States	Amer. (1)	Europe	Africa	Asia	Oceania	Total	All Products (2)
		(billions of cubic feet)							(millions of oil-
									equivalent barrels)
Net proved developed and undeveloped
	reserves of consolidated subsidiaries
January 1, 2015		25,987	1,226	2,383	811	5,460	7,276	43,143	19,013
	Revisions	(6,693)	(45)	63	25	303	23	(6,324)	(595)
	Improved recovery	-	-	-	-	-	-	-	2
	Purchases	182	29	-	-	-	-	211	246
	Sales	(9)	(5)	(56)	-	(89)	-	(159)	(39)
	Extensions/discoveries	1,167	34	-	-	102	-	1,303	1,405
	Production	(1,254)	(112)	(434)	(43)	(447)	(258)	(2,548)	(1,140)
December 31, 2015		19,380	1,127	1,956	793	5,329	7,041	35,626	18,892
Proportional interest in proved reserves
	of equity companies
January 1, 2015		272	-	8,418	-	17,505	-	26,195	6,256
	Revisions	(38)	-	(83)	-	86	-	(35)	11
	Improved recovery	-	-	-	-	-	-	-	-
	Purchases	1	-	-	-	-	-	1	-
	Sales	-	-	-	-	-	-	-	-
	Extensions/discoveries	-	-	-	-	-	-	-	-
	Production	(15)	-	(432)	-	(1,130)	-	(1,577)	(400)
December 31, 2015		220	-	7,903	-	16,461	-	24,584	5,867
Total proved reserves at December 31, 2015		19,600	1,127	9,859	793	21,790	7,041	60,210	24,759

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 678 billion cubic feet in 2013, 627 billion cubic feet in 2014 and 583 billion cubic feet in 2015, as well as proved developed reserves of 368 billion cubic feet in 2013, 300 billion cubic feet in 2014 and 283 billion cubic feet in 2015, and in addition, proved undeveloped reserves of 310 billion cubic feet in 2013, 327 billion cubic feet in 2014 and 300 billion cubic feet in 2015, in which there is a 30.4 percent noncontrolling interest.

(2)   Natural gas is converted to oil-equivalent basis at six million cubic feet per one thousand barrels.

108

Natural Gas and Oil-Equivalent Proved Reserves (continued)
			Natural Gas
				Canada/						Oil-Equivalent
			United	South				Australia/		Total
			States	Amer. (1)	Europe	Africa	Asia	Oceania	Total	All Products (2)
			(billions of cubic feet)							(millions of oil-
										equivalent barrels)
Proved developed reserves, as of
	December 31, 2013
		Consolidated subsidiaries	14,655	664	2,189	779	5,241	969	24,497	11,029
		Equity companies	197	-	6,852	-	17,288	-	24,337	5,643
Proved undeveloped reserves, as of
	December 31, 2013
		Consolidated subsidiaries	11,365	571	621	88	493	6,546	19,684	7,615
		Equity companies	84	-	2,032	-	1,226	-	3,342	929
Total proved reserves at December 31, 2013			26,301	1,235	11,694	867	24,248	7,515	71,860	25,216
Proved developed reserves, as of
	December 31, 2014
		Consolidated subsidiaries	14,169	615	1,870	764	5,031	2,179	24,628	11,199
		Equity companies	194	-	6,484	-	16,305	-	22,983	5,314
Proved undeveloped reserves, as of
	December 31, 2014
		Consolidated subsidiaries	11,818	611	513	47	429	5,097	18,515	7,814
		Equity companies	78	-	1,934	-	1,200	-	3,212	942
Total proved reserves at December 31, 2014			26,259	1,226	10,801	811	22,965	7,276	69,338	25,269
Proved developed reserves, as of
	December 31, 2015
		Consolidated subsidiaries	13,353	552	1,593	750	4,917	1,962	23,127	12,977
		Equity companies	156	-	6,146	-	15,233	-	21,535	4,993
Proved undeveloped reserves, as of
	December 31, 2015
		Consolidated subsidiaries	6,027	575	363	43	412	5,079	12,499	5,915
		Equity companies	64	-	1,757	-	1,228	-	3,049	874
Total proved reserves at December 31, 2015			19,600	1,127	9,859	793	21,790	7,041	60,210	24,759

(See footnotes on previous page)

109

Standardized Measure of Discounted Future Cash Flows

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

					Canada/
Standardized Measure of Discounted			United		South				Australia/
Future Cash Flows			States	America (1)		Europe	Africa	Asia	Oceania	Total
			(millions of dollars)
Consolidated Subsidiaries
	As of December 31, 2013
		Future cash inflows from sales of oil and gas	276,051		293,377	58,235	146,407	245,482	87,808	1,107,360
		Future production costs	113,571		106,884	18,053	30,960	57,328	22,507	349,303
		Future development costs	40,702		43,102	15,215	14,300	10,666	10,191	134,176
		Future income tax expenses	50,144		31,901	17,186	53,766	117,989	16,953	287,939
		Future net cash flows	71,634		111,490	7,781	47,381	59,499	38,157	335,942
		Effect of discounting net cash flows at 10%	42,336		78,700	1,278	18,406	34,878	21,266	196,864
		Discounted future net cash flows	29,298		32,790	6,503	28,975	24,621	16,891	139,078
Equity Companies
	As of December 31, 2013
		Future cash inflows from sales of oil and gas	34,957		-	82,539	-	324,666	-	442,162
		Future production costs	8,231		-	60,518	-	107,656	-	176,405
		Future development costs	3,675		-	2,994	-	8,756	-	15,425
		Future income tax expenses	-		-	7,237	-	70,887	-	78,124
		Future net cash flows	23,051		-	11,790	-	137,367	-	172,208
		Effect of discounting net cash flows at 10%	12,994		-	5,549	-	72,798	-	91,341
		Discounted future net cash flows	10,057		-	6,241	-	64,569	-	80,867
Total consolidated and equity interests in
	standardized measure of discounted
	future net cash flows		39,355		32,790	12,744	28,975	89,190	16,891	219,945

(1)   Includes discounted future net cash flows attributable to Imperial Oil Limited of $25,160 million in 2013, in which there is a 30.4 percent noncontrolling interest.

110

					Canada/
Standardized Measure of Discounted			United		South				Australia/
Future Cash Flows (continued)			States	America (1)		Europe	Africa	Asia	Oceania	Total
			(millions of dollars)
Consolidated Subsidiaries
	As of December 31, 2014
		Future cash inflows from sales of oil and gas	283,767		354,223	42,882	125,125	224,885	78,365	1,109,247
		Future production costs	116,929		140,368	14,358	27,917	57,562	20,467	377,601
		Future development costs	42,276		48,525	13,000	14,603	12,591	8,956	139,951
		Future income tax expenses	49,807		36,787	10,651	44,977	102,581	15,050	259,853
		Future net cash flows	74,755		128,543	4,873	37,628	52,151	33,892	331,842
		Effect of discounting net cash flows at 10%	44,101		87,799	(52)	13,831	30,173	17,326	193,178
		Discounted future net cash flows	30,654		40,744	4,925	23,797	21,978	16,566	138,664
Equity Companies
	As of December 31, 2014
		Future cash inflows from sales of oil and gas	31,924		-	71,031	-	286,124	-	389,079
		Future production costs	8,895		-	50,826	-	99,193	-	158,914
		Future development costs	3,386		-	2,761	-	11,260	-	17,407
		Future income tax expenses	-		-	6,374	-	59,409	-	65,783
		Future net cash flows	19,643		-	11,070	-	116,262	-	146,975
		Effect of discounting net cash flows at 10%	10,970		-	5,534	-	61,550	-	78,054
		Discounted future net cash flows	8,673		-	5,536	-	54,712	-	68,921
Total consolidated and equity interests in
	standardized measure of discounted
	future net cash flows		39,327		40,744	10,461	23,797	76,690	16,566	207,585
Consolidated Subsidiaries
	As of December 31, 2015
		Future cash inflows from sales of oil and gas	144,910		176,452	23,330	57,702	156,378	29,535	588,307
		Future production costs	82,678		115,285	8,735	17,114	50,745	8,889	283,446
		Future development costs	35,016		36,923	11,332	11,170	15,371	8,237	118,049
		Future income tax expenses	5,950		3,042	1,780	14,018	62,353	5,012	92,155
		Future net cash flows	21,266		21,202	1,483	15,400	27,909	7,397	94,657
		Effect of discounting net cash flows at 10%	13,336		13,415	(945)	5,226	17,396	3,454	51,882
		Discounted future net cash flows	7,930		7,787	2,428	10,174	10,513	3,943	42,775
Equity Companies
	As of December 31, 2015
		Future cash inflows from sales of oil and gas	13,065		-	49,061	-	143,692	-	205,818
		Future production costs	6,137		-	35,409	-	57,080	-	98,626
		Future development costs	2,903		-	2,190	-	12,796	-	17,889
		Future income tax expenses	-		-	4,027	-	24,855	-	28,882
		Future net cash flows	4,025		-	7,435	-	48,961	-	60,421
		Effect of discounting net cash flows at 10%	1,936		-	4,287	-	26,171	-	32,394
		Discounted future net cash flows	2,089		-	3,148	-	22,790	-	28,027
Total consolidated and equity interests in
	standardized measure of discounted
	future net cash flows		10,019		7,787	5,576	10,174	33,303	3,943	70,802

(1)   Includes discounted future net cash flows attributable to Imperial Oil Limited of $30,189 million in 2014 and $5,607 million in 2015, in which there is a 30.4 percent noncontrolling interest.

111

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Consolidated and Equity Interests				2013
					Total
				Share of	Consolidated
			Consolidated	Equity Method	and Equity
			Subsidiaries	Investees	Interests
			(millions of dollars)
Discounted future net cash flows as of December 31, 2012			137,549	87,238	224,787
Value of reserves added during the year due to extensions, discoveries,
	improved recovery and net purchases less related costs		11,928	48	11,976
Changes in value of previous-year reserves due to:
	Sales and transfers of oil and gas produced during the year, net of
		production (lifting) costs	(48,742)	(23,757)	(72,499)
	Development costs incurred during the year		24,821	1,389	26,210
	Net change in prices, lifting and development costs		(32,423)	(5,296)	(37,719)
	Revisions of previous reserves estimates		24,353	4,960	29,313
	Accretion of discount		20,596	9,830	30,426
Net change in income taxes			996	6,455	7,451
		Total change in the standardized measure during the year	1,529	(6,371)	(4,842)
Discounted future net cash flows as of December 31, 2013			139,078	80,867	219,945

Consolidated and Equity Interests				2014
					Total
				Share of	Consolidated
			Consolidated	Equity Method	and Equity
			Subsidiaries	Investees	Interests
			(millions of dollars)
Discounted future net cash flows as of December 31, 2013			139,078	80,867	219,945
Value of reserves added during the year due to extensions, discoveries,
	improved recovery and net purchases less related costs		3,497	94	3,591
Changes in value of previous-year reserves due to:
	Sales and transfers of oil and gas produced during the year, net of
		production (lifting) costs	(44,446)	(18,366)	(62,812)
	Development costs incurred during the year		24,189	1,453	25,642
	Net change in prices, lifting and development costs		(50,672)	(13,165)	(63,837)
	Revisions of previous reserves estimates		35,072	3,298	38,370
	Accretion of discount		20,098	8,987	29,085
Net change in income taxes			11,848	5,753	17,601
		Total change in the standardized measure during the year	(414)	(11,946)	(12,360)
Discounted future net cash flows as of December 31, 2014			138,664	68,921	207,585

112

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Consolidated and Equity Interests (continued)				2015
					Total
				Share of	Consolidated
			Consolidated	Equity Method	and Equity
			Subsidiaries	Investees	Interests
			(millions of dollars)
Discounted future net cash flows as of December 31, 2014			138,664	68,921	207,585
Value of reserves added during the year due to extensions, discoveries,
	improved recovery and net purchases less related costs		5,678	-	5,678
Changes in value of previous-year reserves due to:
	Sales and transfers of oil and gas produced during the year, net of
		production (lifting) costs	(20,694)	(9,492)	(30,186)
	Development costs incurred during the year		18,359	1,198	19,557
	Net change in prices, lifting and development costs		(203,224)	(57,478)	(260,702)
	Revisions of previous reserves estimates		6,888	(134)	6,754
	Accretion of discount		17,828	7,257	25,085
Net change in income taxes			79,276	17,755	97,031
		Total change in the standardized measure during the year	(95,889)	(40,894)	(136,783)
Discounted future net cash flows as of December 31, 2015			42,775	28,027	70,802

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OPERATING SUMMARY (unaudited)

			2015	2014	2013	2012	2011
Production of crude oil, natural gas liquids, bitumen and synthetic oil
	Net production		(thousands of barrels daily)
		United States	476	454	431	418	423
		Canada/South America	402	301	280	251	252
		Europe	204	184	190	207	270
		Africa	529	489	469	487	508
		Asia	684	624	784	772	808
		Australia/Oceania	50	59	48	50	51
	Worldwide		2,345	2,111	2,202	2,185	2,312
Natural gas production available for sale
	Net production		(millions of cubic feet daily)
		United States	3,147	3,404	3,545	3,822	3,917
		Canada/South America	261	310	354	362	412
		Europe	2,286	2,816	3,251	3,220	3,448
		Africa	5	4	6	17	7
		Asia	4,139	4,099	4,329	4,538	5,047
		Australia/Oceania	677	512	351	363	331
	Worldwide		10,515	11,145	11,836	12,322	13,162
			(thousands of oil-equivalent barrels daily)
Oil-equivalent production(1)			4,097	3,969	4,175	4,239	4,506
Refinery throughput			(thousands of barrels daily)
		United States	1,709	1,809	1,819	1,816	1,784
		Canada	386	394	426	435	430
		Europe	1,496	1,454	1,400	1,504	1,528
		Asia Pacific	647	628	779	998	1,180
		Other Non-U.S.	194	191	161	261	292
	Worldwide		4,432	4,476	4,585	5,014	5,214
Petroleum product sales (2)
		United States	2,521	2,655	2,609	2,569	2,530
		Canada	488	496	464	453	455
		Europe	1,542	1,555	1,497	1,571	1,596
		Asia Pacific and other Eastern Hemisphere	1,124	1,085	1,206	1,381	1,556
		Latin America	79	84	111	200	276
	Worldwide		5,754	5,875	5,887	6,174	6,413
		Gasoline, naphthas	2,363	2,452	2,418	2,489	2,541
		Heating oils, kerosene, diesel oils	1,924	1,912	1,838	1,947	2,019
		Aviation fuels	413	423	462	473	492
		Heavy fuels	377	390	431	515	588
		Specialty petroleum products	677	698	738	750	773
	Worldwide		5,754	5,875	5,887	6,174	6,413
Chemical prime product sales (2)(3)			(thousands of metric tons)
		United States	9,664	9,528	9,679	9,381	9,250
		Non-U.S.	15,049	14,707	14,384	14,776	15,756
	Worldwide		24,713	24,235	24,063	24,157	25,006

Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.

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

(2)   Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.

(3)   Prime product sales are total product sales excluding carbon black oil and sulfur. Prime product sales include ExxonMobil’s share of equity company volumes and finished-product transfers to the Downstream.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

EXXON MOBIL CORPORATION
By:	/s/    REX W. TILLERSON
		(Rex W. Tillerson, Chairman of the Board)

Dated February 24, 2016

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Randall M. Ebner, Stephen A. Littleton and Jeffrey S. Lynn and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 24, 2016.

/s/    REX W. TILLERSON (Rex W. Tillerson)	Chairman of the Board (Principal Executive Officer)
/s/    MICHAEL J. BOSKIN (Michael J. Boskin)	Director
/s/    PETER BRABECK-LETMATHE (Peter Brabeck-Letmathe)	Director
/s/    URSULA M. BURNS (Ursula M. Burns)	Director
/s/    LARRY R. FAULKNER (Larry R. Faulkner)	Director

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/s/    JAY S. FISHMAN (Jay S. Fishman)	Director
/s/    HENRIETTA H. FORE (Henrietta H. Fore)	Director
/s/    KENNETH C. FRAZIER (Kenneth C. Frazier)	Director
/s/    DOUGLAS R. OBERHELMAN (Douglas R. Oberhelman)	Director
/s/    SAMUEL J. PALMISANO (Samuel J. Palmisano)	Director
/s/    STEVEN S REINEMUND (Steven S Reinemund)	Director
/s/    WILLIAM C. WELDON (William C. Weldon)	Director
/s/    DARREN W. WOODS (Darren W. Woods)	Director
/s/    ANDREW P. SWIGER (Andrew P. Swiger)	Senior Vice President (Principal Financial Officer)
/s/    DAVID S. ROSENTHAL (David S. Rosenthal)	Vice President and Controller (Principal Accounting Officer)

116

INDEX TO EXHIBITS

Exhibit	Description
3(i)	Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001.
3(ii)	By-Laws, as revised to April 27, 2011.
10(iii)(a.1)	2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2012).*
10(iii)(a.2)	Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K of November 28, 2012).*
10(iii)(a.3)	Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.*
10(iii)(a.4)	Standard Provisions for Restricted Stock Unit Agreements – Settlement in Cash (incorporated by reference to Exhibit 10(iii)(a.4) to the Registrant’s Annual Report on Form 10-K for 2013).*
10(iii)(b.1)	Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual Report on Form 10-K for 2013).*
10(iii)(b.2)	Earnings Bonus Unit instrument.*
10(iii)(c.1)	ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant’s Annual Report on Form 10-K for 2014).*
10(iii)(c.2)	ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Annual Report on Form 10-K for 2014).*
10(iii)(c.3)	ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual Report on Form 10-K for 2013).*
10(iii)(d)	ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2011).*
10(iii)(f.1)	2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2013).*
10(iii)(f.2)	Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).*
10(iii)(f.3)	Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2014).*
10(iii)(f.4)	Standing resolution for non-employee director cash fees dated October 26, 2011.*
12	Computation of ratio of earnings to fixed charges.
14	Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2013).
21	Subsidiaries of the registrant.
23	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31.1	Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.
31.2	Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.
31.3	Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.

117

INDEX TO EXHIBITS – (continued)

Exhibit	Description
32.1	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.
32.2	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.
32.3	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.
101	Interactive data files.

*   Compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K.

The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.

118

EX-3.(I)

 

EXHIBIT 3(i)

RESTATED

CERTIFICATE OF INCORPORATION

of

EXXON MOBIL CORPORATION

(As Amended Effective June 20, 2001)

Exxon Mobil Corporation, a corporation organized and existing under the laws of the State of New Jersey, restates and integrates its Certificate of Incorporation, as heretofore restated and amended, to read in full as herein set forth:

FIRST.  The name of the corporation is:

EXXON MOBIL CORPORATION

SECOND.  The address of the corporation’s registered office is 830 Bear Tavern Road, West Trenton, New Jersey 08628-1020.  The name of the corporation's registered agent at such address, upon whom process against the corporation may be served, is Corporation Service Company.

THIRD.  The purposes for which the corporation is organized are to engage in any or all activities within the purposes for which corporations now or at any time hereafter may be organized under the New Jersey Business Corporation Act and under all amendments and supplements thereto, or any revision thereof or any statute enacted to take the place thereof, including but not limited to the following:

(1)        To do all kinds of mining, manufacturing and trading business; transporting goods and merchandise by land or water in any manner; to buy, sell, lease and improve lands; to build houses, structures, vessels, cars, wharves, docks and piers; to lay and operate pipelines; to erect and operate telegraph and telephone lines and lines for conducting electricity; to enter into and carry out contracts of every kind pertaining to its business; to acquire, use, sell and grant licenses under patent rights; to purchase or otherwise acquire, hold, sell, assign and transfer shares of capital stock and bonds or other evidences of indebtedness of corporations, and to exercise all the privileges of ownership including voting upon the securities so held; to carry on its business and have offices and agencies therefor in all parts of the world; and to hold, purchase, mortgage and convey real estate and personal property within or without the State of New Jersey;

(2)        To engage in any activities encompassed within this Article Third directly or through a subsidiary or subsidiaries and to take any and all acts deemed appropriate to promote the interests of such subsidiary or subsidiaries, including, without limiting the foregoing, the following: making contracts and incurring liabilities for the benefit of such subsidiary or subsidiaries; transferring or causing to be transferred to any such subsidiary or

subsidiaries assets of this corporation; guaranteeing dividends on any shares of the capital stock of any such subsidiary; guaranteeing the principal and interest or either of the bonds, debentures, notes or other evidences of indebtedness issued or obligations incurred by any such subsidiary or subsidiaries; securing said bonds, debentures, notes or other evidences of indebtedness so guaranteed by mortgage of or security interest in the property of this corporation; and contracting that said bonds, debentures, notes or other evidences of indebtedness so guaranteed, whether secured or not, may be convertible into shares of this corporation upon such terms and conditions as may be approved by the board of directors;

(3)        To guarantee the bonds, debentures, notes or other evidences of indebtedness issued, or obligations incurred, by any corporation, partnership, limited partnership, joint venture or other association in which this corporation at the time such guarantee is made has a substantial interest or where such guarantee is otherwise in furtherance of the interests of this corporation; and

(4)        To exercise as a purpose or purposes each power granted to corporations by the New Jersey Business Corporation Act or by any amendment or supplement thereto or by any statute enacted to take the place thereof, insofar as such powers authorize or may hereafter authorize corporations to engage in activities. 

FOURTH.  The aggregate number of shares which the corporation shall have authority to issue is nine billion two hundred million (9,200,000,000) shares, divided into two hundred million (200,000,000) shares of preferred stock without par value and nine billion  (9,000,000,000) shares of common stock without par value.

(1)        The board of directors of the corporation is authorized at any time or from time to time (i) to divide the shares of preferred stock into classes and into series within any class or classes of preferred stock; (ii) to determine for any such class or series its designation, relative rights, preferences and limitations; (iii) to determine the number of shares in any such class or series (including a determination that such class or series shall consist of a single share); (iv) to increase the number of shares of any such class or series previously determined by it and to decrease such previously determined number of shares to a number not less than that of the shares of such class or series then outstanding; (v) to change the designation or number of shares, or the relative rights, preferences and limitations of the shares, of any theretofore established class or series no shares of which have been issued; and (vi) to cause to be executed and filed without further approval of the shareholders such amendment or amendments to the Restated Certificate of Incorporation as may be required in order to accomplish any of the foregoing.  In particular, but without limiting the generality of the foregoing, the board of directors is authorized to determine with respect to the shares of any class or series of preferred stock:

(a)        whether the holders thereof shall be entitled to cumulative, non-cumulative or partially cumulative dividends or to no dividends and, with respect to shares entitled to dividends, the dividend rate or rates (which may be fixed or variable and may be made dependent upon facts ascertainable outside of the Restated Certificate of Incorporation) and any other terms and conditions relating to such dividends;

(b)        whether the holders thereof shall be entitled to receive dividends payable on a parity with or subordinate or in preference to the dividends payable on any other class or series of shares of the corporation;

2

(c)        whether, and if so to what extent and upon what terms and conditions, the holders thereof shall be entitled to preferential rights upon the liquidation of, or upon any distribution of the assets of, the corporation;

(d)       whether, and if so upon what terms and conditions, such shares shall be convertible into other securities;

(e)        whether, and if so upon what terms and conditions, such shares shall be redeemable;

(f)        the terms and amount of any sinking fund provided for the purchase or redemption of such shares; and

(g)        the voting rights, if any, to be enjoyed by such shares and the terms and conditions for the exercise thereof.

(2)        Each holder of shares of common stock shall be entitled to one vote for each share of common stock held of record by such holder on all matters on which holders of shares of common stock are entitled to vote.

(3)        No holder of any shares of common or preferred stock of the corporation shall have any right as such holder (other than such right, if any, as the board of directors in its discretion may determine) to purchase, subscribe for or otherwise acquire any unissued or treasury shares, or any option rights, or securities having conversion or option rights, of the corporation now or hereafter authorized.

(4)        The relative voting, dividend, liquidation and other rights, preferences and limitations of the shares of the class of preferred stock designated "Class A Preferred Stock" and the class of preferred stock designated "Class B Preferred Stock" are as set forth in this Article FOURTH and in Exhibit A to this Restated Certificate of Incorporation.

FIFTH.  The following is a list of the names and residences of the original shareholders, and of the number of shares held by each:

H.M. Flagler	of New York City,	One share.
Paul Babcock, Jr.	of Jersey City,	One share.
James McGee	of Plainfield, New Jersey,	One share.
Thos. C. Bushnell	of Morristown, New Jersey,	One share.
John D. Rockefeller	of Cleveland, Ohio,	}
Wm. Rockefeller	of New York City,	}
J.A. Bostwick	of New York City,	}
John D. Archbold	of New York City,	}
O.H. Payne	of Cleveland, Ohio,	}
Wm. G. Warden	of Philadelphia, Pa.,	}
Benj. Brewster	of New York City,	}
Chas. Pratt	of Brooklyn, N.Y.,	}
and H.M. Flagler	of New York City.	}

3

Trustees of Standard Oil Trust, twenty-nine thousand nine hundred and ninety-six shares (29,996), of which twenty-one thousand seven hundred and twenty-four shares (21,724) were issued for property purchased and necessary for the business of this corporation.

SIXTH.  The number of directors of the corporation as of November 30, 1999 is 19 and their names and business office addresses are:

4

Dr. Michael J. Boskin Hoover Institution Stanford University Stanford, California 94305-6010 Mr. René Dahan 5959 Las Colinas Boulevard Irving, Texas 75039-2298 Mr. William T. Esrey Sprint Corporation 2330 Shawnee Mission Pkwy. Westwood, Kansas 66205 Mr. Donald V. Fites 100 N. E. Adams Street Peoria, IL  61629-9210 Mr. Jess Hay Chase Tower 2200 Ross Avenue Dallas, Texas 75201-2764 Mr. Charles A. Heimbold, Jr. Bristol-Myers Squibb Company 345 Park Avenue New York, NY 10154-0037 Mr. James R. Houghton 80 East Market Street Corning, New York 14830 Mr. William R. Howell 6501 Legacy Drive Plano, Texas 75024-3698 Mrs. Helene L. Kaplan Skadden, Arps, Slate, Meagher & Flom 919 Third Avenue New York, NY  10022-3897 Dr. Reatha Clark King General Mills Foundation One General Mills Boulevard Minneapolis, Minnesota 55426 Mr. Phillip E. Lippincott P.O. Box 2159 Park City, Utah 84060 Mr. Harry J. Longwell 5959 Las Colinas Boulevard Irving, Texas 75039-2298 Mrs. Marilyn Carlson Nelson Carlson Companies, Inc. 1405 Xenium Lane North Plymouth, Minnesota 55441 Mr. J. Richard Munro Time Warner Cable 290 Harbor Drive Stamford, CT  06902 Mr. Lucio A. Noto 5959 Las Colinas Boulevard Irving, TX  75039-2298 Mr. Lee R. Raymond 5959 Las Colinas Boulevard Irving, Texas 75039-2298 Mr. Eugene A. Renna 5959 Las Colinas Boulevard Irving, Texas 75039-2298 Mr. Walter V. Shipley The Chase Manhattan Corporation 270 Park Avenue New York, New York 10017-2070 Mr. Robert E. Wilhelm 5959 Las Colinas Boulevard Irving, Texas 75039-2298

5

SEVENTH.  The number of directors at any time may be increased or diminished by vote of the board of directors, and in case of any such increase the board of directors shall have power to elect each such additional director to hold office until the next succeeding annual meeting of shareholders and until his successor shall have been elected and qualified.

The board of directors, by the affirmative vote of a majority of the directors in office, may remove a director or directors for cause where, in the judgment of such majority, the continuation of the director or directors in office would be harmful to the corporation and may suspend the director or directors for a reasonable period pending final determination that cause exists for such removal.

The board of directors from time to time shall determine whether and to what extent, and at what times and places, and under what conditions and regulations, the accounts and books of the corporation, or any of them, shall be open to the inspection of the shareholders; and no shareholder shall have any right of inspecting any account or book or document of the corporation, except as conferred by statute or authorized by the board of directors, or by a resolution of the shareholders.

EIGHTH.  The following action may be taken by the affirmative vote of a majority of the votes cast by the holders of shares of the corporation entitled to vote thereon:

(1)        The adoption by the shareholders of a proposed amendment of the certificate of incorporation of the corporation;

(2)        The adoption by the shareholders of a proposed plan of merger or consolidation involving the corporation;

(3)        The approval by the shareholders of a sale, lease, exchange, or other disposition of all, or substantially all, the assets of the corporation otherwise than in the usual and regular course of business as conducted by the corporation; and

(4)        Dissolution.

NINTH.  Except as otherwise provided by statute or by this certificate of incorporation or the by-laws of the corporation as in each case the same may be amended from time to time, all corporate powers may be exercised by the board of directors.  Without limiting the foregoing, the board of directors shall have power, without shareholder action:

(1)        To authorize the corporation to purchase, acquire, hold, lease, mortgage, pledge, sell and convey such property, real, personal and mixed, without as well as within the State of New Jersey, as the board of directors may from time to time determine, and in payment for any property to issue, or cause to be issued, shares of the corporation, or bonds, debentures, notes or other obligations or evidence of indebtedness thereof secured by pledge, security interest or mortgage, or unsecured; and

(2)        To authorize the borrowing of money, the issuance of bonds, debentures, notes and other obligations or evidences of indebtedness of the corporation, secured or unsecured, and the inclusion of provisions as to redeemability and convertibility into shares of

6

stock of the corporation or otherwise, and, as security for money borrowed or bonds, debentures, notes and other obligations or evidences of indebtedness issued by the corporation, the mortgaging or pledging of any property, real, personal, or mixed, then owned or thereafter acquired by the corporation.

TENTH.  To the full extent from time to time permitted by law, no director or officer of the corporation shall be personally liable to the corporation or its shareholders for damages for breach of any duty owed to the corporation or its shareholders.  Neither the amendment or repeal of this Article, nor the adoption of any provision of this certificate of incorporation inconsistent with this Article, shall eliminate or reduce the protection afforded by this Article to a director or officer of the corporation with respect to any matter which occurred, or any cause of action, suit or claim which but for this Article would have accrued or arisen, prior to such amendment, repeal or adoption.

7

EXHIBIT A

PART I

Class A Preferred Stock

Section 1.  Designation and Amount; Special Purpose Restricted Transfer Issue. 

(A)       The shares of this class of preferred stock shall be designated as "Class A Preferred Stock" (referred to herein as the "Class A Preferred Stock") and the aggregate number of shares constituting such class which the Corporation shall have the authority to issue is 16,500,000.  The shares of this class shall have a stated value of $61.50 per share (the "Stated Value").

(B)       Shares of Class A Preferred Stock shall be issued only to a trustee acting on behalf of the Plan (as defined in Section 9(F)(vii)).  In the event of any transfer of shares of Class A Preferred Stock to any person other than the Corporation or the trustee of the Plan, the shares of Class A Preferred Stock so transferred, upon such transfer and without any further action by the Corporation or the holder, shall be automatically converted into shares of the Corporation’s Common Stock without par value (the "Common Stock") pursuant to Section 5 hereof and no such transferee shall have any of the voting powers, preferences and relative, participating, optional or special rights ascribed to shares of Class A Preferred Stock hereunder but, rather, only the powers and rights pertaining to the Common Stock into which such shares of Class A Preferred Stock shall be so converted.  In the event of such a conversion, the transferee of the shares of Class A Preferred Stock shall be treated for all purposes as the record holder of the shares of Common Stock into which such shares of Class A Preferred Stock have been automatically converted as of the date of such transfer; provided, however, that the pledge of Class A Preferred Stock as collateral under any credit agreement for the financing or refinancing of the initial purchase of the Class A Preferred Stock by the Plan shall not constitute a transfer for purposes of this Section 1.  Certificates representing shares of Class A Preferred Stock shall be legended to reflect such restrictions on transfer.  Notwithstanding the foregoing provisions of this Section 1 (B), shares of Class A Preferred Stock (i) upon allocation to the account of a participant in the Plan, shall be converted into shares of Common Stock pursuant to Section 5 hereof and the shares of Common Stock issued upon such conversion may be transferred by the holder thereof as permitted by law and (ii) shall be redeemable by the Corporation upon the terms and conditions provided by Sections 6, 7 and 8 hereof.

Section 2.  Dividends and Distributions. 

(A)       Subject to the provisions for adjustment hereinafter set forth, the holders of shares of Class A Preferred Stock shall be entitled to receive, when, as and if declared by the Board of Directors out of funds available under applicable law and the Certificate of Incorporation, cumulative cash dividends ("Preferred Dividends") in an amount per share equal to $4.68 per annum and no more, payable (x) monthly in arrears, one-twelfth on the 20th day of each month, commencing on July 20, 1989 and ending on June 20, 1990, and thereafter (y) quarterly in arrears, one-quarter on the 20th day of each March, June, September and December in each year (each such monthly and quarterly date a "Dividend Payment Date"), to holders of record at the start of business on such Dividend Payment Date.  In the event that any Dividend Payment Date shall occur on any day other than a "Business Day" (as defined in Section 9(F)(i)),

8

the dividend payment due on such Dividend Payment Date shall be paid on the Business Day immediately succeeding such Dividend Payment Date.  Preferred Dividends shall begin to accrue on outstanding shares of Class A Preferred Stock from the date of issuance of such shares of Class A Preferred Stock.  Preferred Dividends shall accrue on a daily basis whether or not the Corporation shall have earnings or surplus at the time.  Preferred Dividends accrued after the date of issuance for any period less than a full monthly or quarterly period, as the case may be, between Dividend Payment Dates shall be computed on the basis of a 360-day year consisting of twelve 30-day months and such a proportional dividend shall accrue for the period from the date of issuance until the end of the dividend payment period in which such issuance occurs.  Accumulated but unpaid Preferred Dividends shall accumulate as of the Dividend Payment Date on which they first become payable, but no interest shall accrue on accumulated but unpaid Preferred Dividends.

(B)       So long as any Class A Preferred Stock shall be outstanding, no dividend shall be declared or paid or set apart for payment on any other class of stock ranking on a parity with the Class A Preferred Stock as to dividends ("Parity Stock"), unless there shall also be or have been declared and paid or set apart for payment on the Class A Preferred Stock dividends ratably in proportion to the respective amounts of dividends (a) accumulated and unpaid through all dividend payment periods for the Class A Preferred Stock ending on or before the dividend payment date of such Parity Stock and (b) accumulated and unpaid on such Parity Stock through the dividend payment period on such Parity Stock next preceding such dividend payment date.  So long as any Class A Preferred Stock shall be outstanding, in the event that full cumulative dividends on the Class A Preferred Stock have not been declared and paid or set apart for payment for all prior dividend payment periods, the Corporation shall not declare or pay or set apart for payment any dividends or make any other distributions on, or make any payment on account of the purchase, redemption or other retirement of, any other class of stock or series thereof of the Corporation ranking as to dividends junior to the Class A Preferred Stock ("Junior Stock") until full cumulative and unpaid dividends on the Class A Preferred Stock shall have been paid or declared and set apart for payment; provided, however, that the foregoing shall not apply to (i) any dividend payable solely in any shares of any Junior Stock, or (ii) the acquisition of shares of any Junior Stock either (x) pursuant to any employee or director incentive or benefit plan or arrangement (including any employment, severance or consulting agreement) of the Corporation or any subsidiary of the Corporation heretofore or hereafter adopted or (y) in exchange solely for shares of any other Junior Stock. 

Section 3.  Voting Rights.  The holders of shares of Class A Preferred Stock shall have the following voting rights:

(A)       The holders of Class A Preferred Stock shall be entitled to vote on all matters submitted to a vote of the holders of Common Stock of the Corporation, voting together as one class with the holders of Common Stock and any other class or series of preferred stock so voting as one class.  Each share of the Class A Preferred Stock shall entitle the holder thereof to a number of votes equal to the number of shares of Common Stock into which such share of Class A Preferred Stock could be converted pursuant to the first sentence of Section 5(A) hereof on the record date for determining the shareholders entitled to vote, rounded to the nearest one-tenth of a vote; it being understood that whenever the "Conversion Ratio" (as defined in Section 5 hereof) is adjusted pursuant to Section 9 hereof, the voting rights of the Class A Preferred Stock shall also be similarly adjusted.

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(B)       Except as otherwise required by law, holders of Class A Preferred Stock shall have no special voting rights and their consent shall not be required (except to the extent they are entitled to vote with holders of Common Stock or any other class or series of preferred stock) for the taking of any corporate action.

Section 4.  Liquidation, Dissolution or Winding-Up. 

(A)       Upon any voluntary or involuntary liquidation, dissolution or winding-up of the Corporation, the holders of Class A Preferred Stock shall be entitled to receive out of assets of the Corporation which remain after satisfaction in full of all valid claims of creditors of the Corporation and which are available for payment to shareholders, and subject to the rights of the holders of any class of stock of the Corporation ranking senior to or on a parity with the Class A Preferred Stock in respect of distributions upon liquidation, dissolution or winding-up of the Corporation, before any amount shall be paid or distributed among the holders of Common Stock or any other class of stock ranking junior to the Class A Preferred Stock in respect of distributions upon liquidation, dissolution or winding-up of the Corporation, liquidating distributions in an aggregate amount of $61.50 per share of Class A Preferred Stock plus an amount equal to all accrued and unpaid dividends thereon to the date fixed for distribution, and no more.  If upon any liquidation, dissolution or winding-up of the Corporation, the amounts payable with respect to the Class A Preferred Stock and any other class of stock ranking as to any such distribution on a parity with the Class A Preferred Stock are not paid in full, the holders of the Class A Preferred Stock and such other class of stock shall share ratably in any distribution of assets in proportion to the full respective preferential amounts to which they are entitled.  After payment of the full amount to which they are entitled as provided by the foregoing provisions of this Section 4(A), the holders of shares of Class A Preferred Stock shall not be entitled to any further right or claim to any of the remaining assets of the Corporation.

(B)       Neither the merger, consolidation or combination of the Corporation with or into any other corporation, nor the sale, lease, transfer or other exchange of all or any portion of the assets of the Corporation (or any purchase or redemption of some or all of the shares of any class or series of stock of the Corporation), shall be deemed to be a dissolution, liquidation or winding-up of the affairs of the Corporation for purposes of this Section 4, but the holders of Class A Preferred Stock shall nevertheless be entitled in the event of any such transaction to the rights provided by Section 8 hereof.

(C)       Written notice of any voluntary or involuntary liquidation, dissolution or winding-up of the Corporation, stating the payment date or dates when, and the place or places where, the amounts distributable to holders of Class A Preferred Stock and any other class or series of preferred stock in such circumstances shall be payable, and stating that, except in the case of Class A Preferred Stock represented by uncertificated shares, such payment will be made only after the surrender (or submission for notation of any partial payment) of such holder's certificates representing shares of Class A Preferred Stock, shall be given by first class mail, postage prepaid, mailed not less than twenty (20) days prior to any payment date stated therein, to the holders of Class A Preferred Stock, at the address shown on the books of the Corporation or any transfer agent for the Class A Preferred Stock.

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Section 5.  Conversion into Common Stock. 

(A)       A holder of shares of Class A Preferred Stock shall be entitled at any time, but not later than the close of business on the Redemption Date (as hereinafter defined) of such shares pursuant to Section 6, 7 or 8 hereof, to cause any or all of such shares to be converted into a number of shares of Common Stock for each share of Class A Preferred Stock which initially shall be one and which shall be adjusted as hereinafter provided (and, as so adjusted, is hereinafter sometimes referred to as the "Conversion Ratio").  In addition to the foregoing and subject to Section 5(B) hereof, a holder of shares of Class A Preferred Stock upon allocation of such shares to the account of a participant in the Plan shall be required to convert each such share of Class A Preferred Stock into the greater of (i) that number of shares of Common Stock which shall be the quotient obtained by dividing the Stated Value of each share of Class A Preferred Stock by the greater of (x) $15 divided by the Conversion Ratio or (y) the average of the high and low sales prices for a share of Common Stock on the trading day next preceding the Conversion Date (as hereinafter defined) on which one or more sales of shares of Common Stock occur, all as reported on the Composite Tape (as hereinafter defined), or (ii) that number of shares of Common Stock equal to the Conversion Ratio.  The Corporation’s determination in good faith in respect of the number of shares to be issued upon any and all conversions pursuant to the preceding sentence shall be conclusive.

(B)       Any holder of shares of Class A Preferred Stock desiring or required to convert such shares into shares of Common Stock shall surrender the certificate or certificates representing the shares of Class A Preferred Stock being converted, duly assigned or endorsed for transfer to the Corporation (or accompanied by duly executed stock powers relating thereto) in case of a request for registration in a name other than that of such holder, at the offices of the Corporation or the transfer agent for the Common Stock accompanied by written notice of conversion.  Such notice of conversion shall specify (i) the number of shares of Class A Preferred Stock to be converted, and the name or names in which such holder wishes the certificate or certificates for Common Stock and for any shares of Class A Preferred Stock not to be so converted to be issued (or the name or names in which ownership of such shares is to be registered in the event that they are to be uncertificated), (ii) the address or addresses to which such holder wishes delivery to be made of such new certificates to be issued upon such conversion, and (iii) whether the conversion is being effected pursuant to the second sentence of Section 5(A) hereof.

(C)       A conversion of shares of Class A Preferred Stock into shares of Common Stock pursuant to Section 5(A) shall be effective immediately before the close of business on the day of the later of (i) the surrender to the Corporation of the certificate or certificates for the shares of Class A Preferred Stock to be converted, duly assigned or endorsed for transfer to the Corporation (or accompanied by duly executed stock powers relating thereto) in case of a request for registration in a name other than that of such holder and (ii) the giving of the notice of conversion as provided herein (the "Conversion Date").  On and after such Conversion Date, the person or persons entitled to receive the Common Stock issuable upon such conversion shall be treated for all purposes as the record holder or holders of such shares of Common Stock.

(D)       Promptly after the Conversion Date for shares of Class A Preferred Stock to be converted, the Corporation or the transfer agent for the Common Stock shall issue and send by hand delivery (with receipt to be acknowledged) or by first class mail, postage prepaid, to the holder of such shares or to such holder's designee, at the address designated by such holder, a

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certificate or certificates for the number of shares of Common Stock to which such holder shall be entitled upon conversion.  In the event that there shall have been surrendered a certificate or certificates representing shares of Class A Preferred Stock only part of which are to be converted, the Corporation or the transfer agent for the Common Stock shall issue and deliver to such holder or such holder's designee a new certificate or certificates representing the number of shares of Class A Preferred Stock which shall not have been converted.

(E)       The Corporation shall not be obligated to deliver to holders of Class A Preferred Stock any fractional share or shares of Common Stock issuable upon any conversion of such shares of Class A Preferred Stock, but in lieu thereof may make a cash payment in respect thereof in any manner permitted by law.  The determination in good faith by the Corporation of the amount of any such cash payments shall be conclusive.

(F)       The Corporation shall at all times reserve and keep available out of its authorized and unissued and/or treasury Common Stock solely for issuance upon the conversion of shares of Class A Preferred Stock as herein provided, free from any preemptive rights, the maximum number of shares of Common Stock as shall from time to time be issuable upon the conversion of all shares of Class A Preferred Stock then outstanding.

Section 6.  Redemption at the Option of the Corporation. 

(A)       The Class A Preferred Stock shall be redeemable, in whole or in part, at the option of the Corporation at any time at the Stated Value, plus an amount equal to all accrued and unpaid dividends thereon to the date fixed for redemption (the close of business on such date being referred to as the "Redemption Date"); provided  that such redemption may be made on or after December 20, 1990 and prior to July 20, 1995 only if (i) the Corporation shall have requested that the trustee of the Plan repay the indebtedness incurred by such trustee to purchase the shares of Class A Preferred Stock and (ii) either (x) Section 404(k) of the Code (as hereinafter defined) is repealed or amended or the Internal Revenue Service or the Treasury Department promulgates a Revenue Ruling or Regulation or a federal Court of Appeals issues a decision involving the Corporation, at any time on or after December 20, 1990 and prior to July 20, 1995 with the effect that less than 100% of the dividends payable on the shares of any capital stock of the Corporation including, without limitation, Class A Preferred Stock or Common Stock held in the Plan is deductible by the Corporation, when paid to participants in the Plan or their beneficiaries or used to repay indebtedness as described in Section 404(k) of the Code, from its gross income for purposes of determining its liability for the federal income tax imposed by Section 11 of the Code or (y) the Code is amended at any time on or after December 20, 1990 and prior to July 20, 1995 (other than to change the rate of any existing tax imposed by the Code) or the Internal Revenue Service or the Treasury Department promulgates a Revenue Ruling or Regulation or a federal Court of Appeals issues a decision involving the Corporation, with the effect that the Corporation's liability for the alternative minimum tax imposed by Section 55 of the Code, the general federal income tax imposed by Section 11 of the Code or any other tax hereafter imposed by the Code is increased solely by reason of its claiming a deduction in respect of dividends paid on the shares of any capital stock of the Corporation including, without limitation, Class A Preferred Stock or Common Stock held in the Plan in a manner consistent with Section 404(k) of the Code.  Payment of the redemption price shall be made by the Corporation in cash or shares of Common Stock or a combination thereof, as permitted by paragraph (C) of this Section 6.  From and after the Redemption Date, dividends on shares of Class A Preferred Stock called for redemption will cease to accrue, such shares will no longer be

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deemed to be outstanding and all rights in respect of such shares of the Corporation shall cease, except the right to receive the redemption price.  No interest shall accrue at the redemption price after the Redemption Date.  If less than all of the outstanding shares of Class A Preferred Stock are to be redeemed, the Corporation shall either redeem a portion of the shares of each holder determined pro rata based on the number of shares held by each holder or shall select the shares to be redeemed by lot or as may be otherwise determined by the Board of Directors of the Corporation.

(B)       Unless otherwise required by law, notice of redemption pursuant to paragraph (A) of this Section 6 will be sent to the holders of Class A Preferred Stock at the address shown on the books of the Corporation or any transfer agent for the Class A Preferred Stock by first class mail, postage prepaid, mailed not less than thirty (30) days nor more than sixty (60) days prior to the Redemption Date.  Such Class A Preferred Stock shall continue to be entitled to the conversion rights provided in Section 5 hereof through such Redemption Date.  Each such notice shall state: (i) the Redemption Date; (ii) the total number of shares of the Class A Preferred Stock to be redeemed and, if fewer than all the shares held by such holder are to be redeemed, the number of such shares to be redeemed from such holder; (iii) the redemption price and the intended form of payment; (iv) the place or places where certificates for such shares are to be surrendered for payment of the redemption price; (v) that dividends on the shares to be redeemed will cease to accrue on such Redemption Date; and (vi) a summary of the conversion rights of the shares to be redeemed, the period within which conversion rights may be exercised, and the Conversion Ratio in effect at the time.  Upon surrender of the certificate for any shares so called for redemption and not previously converted (or upon giving the notice of redemption in the case of uncertificated shares), but not earlier than the Redemption Date, the Corporation shall pay to the holder of such shares or its designee the redemption price set forth pursuant to this Section 6.

(C)       The Corporation, at its option, may make payment of the redemption price required upon redemption of shares of Class A Preferred Stock pursuant to Section 6 or 7 hereof in cash or in shares of Common Stock or in a combination of such shares and cash, any such shares of Common Stock to be valued for such purpose at their Fair Market Value (as defined in Section 9(F)(iii)) on the Redemption Date.  Any shares of Common Stock so issued or delivered (or issued or delivered pursuant to Section 7) shall be deemed to have been issued or delivered to the holder of the Class A Preferred Stock as of the Redemption Date and such holder shall be deemed to have become the record holder thereof as of the Redemption Date.

Section 7.  Other Redemption Rights. 

Shares of Class A Preferred Stock shall be redeemed by the Corporation for cash or, if the Corporation so elects, in shares of Common Stock, or a combination of such shares and cash (any such shares of Common Stock to be valued for such purpose in accordance with Section 6(C)), at a redemption price equal to the Stated Value plus accrued and unpaid dividends thereon to the date fixed for redemption, at the option of the holder, at any time and from time to time upon notice to the Corporation given not less than five (5) Business Days prior to the Redemption Date fixed by the holder in such notice (i) in the event that the Plan is determined by the Internal Revenue Service not to be qualified within the meaning of Sections 401(a) and 4975(e)(7) of the Internal Revenue Code of 1986, as amended from time to time (the "Code") or (ii) in the event that the Plan is terminated in accordance with its terms.

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Section 8.  Consolidation, Combination, Merger, Etc. 

(A)       In the event that the Corporation shall consummate any consolidation, combination, merger or substantially similar transaction, pursuant to which the outstanding shares of Common Stock are by operation of law exchanged solely for or changed, reclassified or converted solely into stock of any successor or resulting corporation (including the Corporation) that constitutes "qualifying employer securities" with respect to a holder of Class A Preferred Stock within the meaning of Section 409(1) of the Code and Section 407(d)(5) of the Employee Retirement Income Security Act of 1974, as amended, or any successor provisions of law, and, if applicable, for a cash payment in lieu of fractional shares, if any, the shares of Class A Preferred Stock of such holder shall in connection therewith be exchanged for or converted into preferred stock of such successor or resulting corporation, having in respect of such corporation insofar as possible the same powers, preferences and relative, participating, optional or other special rights (including the redemption rights provided by Sections 6, 7 and 8 hereof), and the qualifications, limitations or restrictions thereon, that the Class A Preferred Stock had immediately prior to such transaction, except that after such transaction each share of the Class A Preferred Stock shall be convertible, otherwise on the terms and conditions provided by Section 5 hereof, into the number and kind of qualifying employer securities so receivable by a holder of the number of shares of Common Stock into which such shares of Class A Preferred Stock could have been converted pursuant to the first sentence of Section 5(A) hereof immediately prior to such transaction; provided, however, that if by virtue of the structure of such transaction, a holder of Common Stock is required to make an election with respect to the nature and kind of consideration to be received in such transaction, such holder of shares of Class A Preferred Stock shall be entitled to make an equivalent election as to the nature and kind of consideration it shall receive, and if such election cannot practicably be made by the holders of the Class A Preferred Stock, then the shares of Class A Preferred Stock shall, by virtue of such transaction and on the same terms as apply to the holders of Common Stock, be convertible into or exchangeable for the aggregate amount of qualifying employer securities (payable in like kind and proportion) receivable by a holder of the number of shares of Common Stock into which such shares of Class A Preferred Stock could have been converted immediately prior to such transaction if such holder of Common Stock failed to exercise any rights of election to receive any kind or amount of qualifying employer securities receivable upon such transaction (provided  that, if the kind or amount of qualifying employer securities receivable upon such transaction is not the same for each non-electing share, then the kind and amount of qualifying employer securities receivable upon such transaction for each such non-electing share shall be the kind and amount so receivable per share by a plurality of the non-electing shares).  The conversion rights of the class of preferred stock of such successor or resulting corporation for which the Class A Preferred Stock is exchanged or into which it is converted, shall successively be subject to adjustments pursuant to Section 9 hereof after any such transactions as nearly equivalent as practicable to the adjustments provided for by such Section prior to such transaction.  The Corporation shall not consummate any such merger, consolidation or similar transaction unless the successor or resulting corporation shall have agreed to recognize and honor the rights of the holders of Class A Preferred Stock set forth in this Section 8(A).

(B)       In the event that the Corporation shall consummate any consolidation, combination, merger or substantially similar transaction, pursuant to which the outstanding shares of Common Stock are by operation of law exchanged for or changed, reclassified or converted into other stock or securities or cash or any other property, or any combination thereof,

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other than solely qualifying employer securities (as referred to in Section 8(A)) and cash payments, if applicable, in lieu of fractional shares, outstanding shares of Class A Preferred Stock shall, without any action on the part of the Corporation or any holder thereof (but subject to Section 8(C)), be deemed to have been converted pursuant to the first sentence of Section 5(A) hereof immediately prior to the consummation of such merger, consolidation, combination or similar business combination transaction into the number of shares of Common Stock into which such shares of Class A Preferred Stock could have been converted pursuant to the first sentence of Section 5(A) hereof at such time so that each share of Class A Preferred Stock shall, by virtue of such transaction and on the same terms as apply to the holders of Common Stock, be converted into or exchanged for the aggregate amount of stock, securities, cash or other property (payable in like kind and proportion) receivable by a holder of the number of shares of Common Stock into which such share of Class A Preferred Stock could have been converted pursuant to the first sentence of Section 5(A) hereof immediately prior to such transaction; provided, however, that if by virtue of the structure of such transaction, a holder of Common Stock is required to make an election with respect to the nature and kind of consideration to be received in such transaction, the holder of Class A Preferred Stock shall be entitled to make an equivalent election as to the kind of consideration it shall receive, and if such election cannot practicably be made by the holders of the Class A Preferred Stock, then the shares of Class A Preferred Stock shall, by virtue of such transaction and on the same terms as apply to the holders of Common Stock, be converted into or exchanged for the aggregate amount of stock, securities, cash or other property (payable in like kind and proportion) receivable by a holder of the number of shares of Common Stock into which such shares of Class A Preferred Stock could have been converted immediately prior to such transaction if such holder of Common Stock failed to exercise any rights of election as to the kind or amount of stock, securities, cash or other property receivable upon such transaction (provided that, if the kind or amount of stock, securities, cash or other property receivable upon such transaction is not the same for each non-electing share, then the kind and amount of stock, securities, cash or other property receivable upon such transaction for each such non-electing share shall be the kind and amount so receivable per share by a plurality of the non- electing shares).

(C)       In the event the Corporation shall enter into any agreement providing for any consolidation, combination, merger or substantially similar transaction described in Section 8(B), then the Corporation shall as soon as practicable thereafter (and in any event at least twenty (20) Business Days before consummation of such transaction) give notice of such agreement and the material terms thereof to each holder of Class A Preferred Stock and each holder shall have the right to elect, by written notice to the Corporation, to receive, upon consummation of such transaction (if and when such transaction is consummated), from the Corporation or the successor of the Corporation, in redemption and retirement of such Class A Preferred Stock, a cash payment equal to the amount payable in respect of shares of Class A Preferred Stock upon redemption pursuant to Section 6(A) hereof as if the date of the consummation of such transaction was the Redemption Date.  No such notice of redemption shall be effective unless given to the Corporation prior to the close of business on the second Business Day prior to consummation of such transaction, unless the Corporation or the successor of the Corporation shall waive such prior notice, but any notice of redemption so given prior to such time may be withdrawn by notice of withdrawal given to the Corporation prior to the close of business on the second Business Day prior to consummation of such transaction.

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Section 9.  Anti-dilution Adjustments. 

(A)       In the event the Corporation shall, at any time or from time to time while any of the shares of the Class A Preferred Stock are outstanding, (i) pay a dividend or make a distribution in respect of the Common Stock in shares of Common Stock, (ii) subdivide the outstanding shares of Common Stock or (iii) combine the outstanding shares of Common Stock into a smaller number of shares, in each case whether by reclassification of shares, recapitalization of the Corporation (including a recapitalization effected by a merger or consolidation to which Section 8 hereof does not apply) or otherwise, the Conversion Ratio in effect immediately prior to such action shall be adjusted by multiplying such Conversion Ratio by a fraction, the numerator of which is the number of shares of Common Stock outstanding immediately after such event, and the denominator of which is the number of shares of Common Stock outstanding immediately before such event.  An adjustment made pursuant to this Section 9(A) shall be given effect, upon payment of such a dividend or distribution, as of the record date for the determination of shareholders entitled to receive such dividend or distribution (on a retroactive basis) and in the case of a subdivision or combination shall become effective immediately as of the effective date thereof.

(B)       In the event the Corporation shall, at any time or from time to time while any shares of Class A Preferred Stock are outstanding, issue rights, options or warrants to all holders of its outstanding Common Stock, without any charge to such holders, entitling them (for a period expiring within forty-five (45) days after the record date mentioned below) to subscribe for or purchase shares of Common Stock at a price per share which is more than 2% lower at the record date mentioned below than the then Current Market Price per share of Common Stock, the Conversion Ratio in effect immediately prior to such action shall, subject to paragraphs (D) and (E) of this Section 9, be adjusted by multiplying such Conversion Ratio by a fraction (i) the numerator of which shall be the number of shares of Common Stock outstanding on the date of issuance of such rights, options or warrants plus the number of additional shares of Common Stock issued upon exercise thereof, and (ii) the denominator of which shall be the number of shares of Common Stock outstanding on the date of issuance of such rights, options or warrants plus the number of shares which the aggregate offering price of the total number of shares of Common Stock so issued would purchase at the then Current Market Price per share of Common Stock.  Such adjustment shall be made whenever such rights, options or warrants have expired, and shall become effective retroactively immediately after the record date for the determination of shareholders entitled to receive such rights, options or warrants on the basis of the number of rights, options or warrants actually exercised.

(C)       In the event the Corporation shall, at any time or from time to time while any of the shares of Class A Preferred Stock are outstanding, make an Extraordinary Distribution (as defined in Section 9(F)(ii)) in respect of the Common Stock, whether by dividend, distribution, reclassification of shares or recapitalization of the Corporation (other than a recapitalization or reclassification effected by a merger, combination or consolidation to which Section 8 hereof applies), the Conversion Ratio in effect immediately prior to such Extraordinary Distribution shall, subject to paragraphs (D) and (E) of this Section 9, be adjusted by multiplying such Conversion Ratio by a fraction, the numerator of which shall be the product of (i) the number of shares of Common Stock outstanding immediately before such Extraordinary Distribution and (ii) the Fair Market Value of a share of Common Stock on the Valuation Date (as defined in Section 9(F)(vi)) with respect to an Extraordinary Distribution, and the

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denominator of which shall be (i) the product of (x) the number of shares of Common Stock outstanding immediately before such Extraordinary Distribution and (y) the Fair Market Value of a share of Common Stock on the Valuation Date with respect to an Extraordinary Distribution, minus  (ii) the Fair Market Value of the Extraordinary Distribution on the Valuation Date.  The Corporation shall send each holder of Class A Preferred Stock notice of its intent to make any Extraordinary Distribution at the same time as, or as soon as practicable after, such intent is first communicated (including by announcement of a record date in accordance with the rules of the principal stock exchange on which the Common Stock is listed or admitted to trading) to holders of Common Stock.  Such notice shall indicate the intended record date and the amount and nature of such dividend or distribution, and the Conversion Ratio in effect at such time.

(D)       Notwithstanding any other provisions of this Section 9, the Corporation shall not be required to make any adjustment of the Conversion Ratio unless such adjustment would require an increase or decrease of at least one percent (1%) in the Conversion Ratio.  Any lesser adjustment shall be carried forward and shall be made no later than the time of, and together with, the next subsequent adjustment which, together with any adjustment or adjustments so carried forward, shall amount to an increase or decrease of at least one percent (1%) in the Conversion Ratio.

(E)       The Corporation shall be entitled to make such additional adjustments in the Conversion Ratio, in addition to those required by the foregoing provisions of this Section 9, as shall be necessary in order that any dividend or distribution in shares of capital stock of the Corporation, subdivision, reclassification or combination of shares of stock of the Corporation or any recapitalization of the Corporation shall not be taxable to holders of the Common Stock.

(F)       For purposes of this Exhibit A, the following definitions shall apply:

(i)         "Business Day" shall mean each day that is not a Saturday, Sunday or a day which state or federally chartered banking institutions in New York are required or authorized to be closed.

(ii)        "Extraordinary Distribution" shall mean any dividend or other distribution (effected while any of the shares of Class A Preferred Stock are outstanding) of (x) cash to the extent that such dividend or distribution when added to the amount of all cash dividends and distributions paid during the preceding period of twelve (12) calendar months exceeds fifteen percent (15%) of the aggregate Fair Market Value of all shares of Common Stock outstanding on the declaration date for such Extraordinary Distribution and/or (y) any shares of capital stock of the Corporation (other than shares of Common Stock), other securities of the Corporation, evidences of indebtedness of the Corporation or any other person or any other property (including shares of any subsidiary of the Corporation), or any combination thereof, but excluding rights, options or warrants to which Section 9(B) refers (without regard to the subscription or purchase price provided for therein).

(iii)       "Fair Market Value" shall mean, as to shares of Common Stock or any other class of publicly traded capital stock or securities of the Corporation or any other issuer which are publicly traded, the average of the Current Market Prices of such shares or securities for each day of the Adjustment Period.  The "Fair Market Value" of any security which is not publicly traded or of any other property shall mean the fair

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value thereof as determined by an independent investment banking or appraisal firm experienced in the valuation of such securities or property, which firm shall be selected in good faith by the Board of Directors of the Corporation or a committee thereof, or, if no such investment banking or appraisal firm is in the good faith judgment of the Board of Directors or such committee available to make such determination, as determined in good faith by the Board of Directors of the Corporation or such committee.

(iv)       "Current Market Price" of publicly traded shares of Common Stock or any other class of capital stock or other security of the Corporation or any other issuer shall mean (I) the last reported sales price, regular way, or, if no sale takes place on such day, the average of the reported closing bid and asked prices, regular way, in either case as reported on the Composite Tape for New York Stock Exchange transactions (the "Composite Tape") or, (II) if such security is not listed or admitted to trading on the New York Stock Exchange (the "NYSE"), on the principal national securities exchange on which such security is listed or admitted to trading or, (III) if not listed or admitted to trading on any national securities exchange, on the National Market System of the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ National Market System") or, (IV) if such security is not quoted on the NASDAQ National Market System, the average of the closing bid and asked prices on each such day in the over-the-counter market as reported by NASDAQ or, (V) if bid and asked prices for such security on each such day shall not have been reported through NASDAQ, the average of the bid and asked prices for such day as furnished by any NYSE member firm regularly making a market in such security selected for such purposes by the Board of Directors of the Corporation or a committee thereof, in each case, on each trading day during the Adjustment Period; provided, however, in determining the Current Market Price, the value (as reasonably determined by the Board of Directors of the Corporation or a committee thereof) of any "due-bill" or similar instrument which is then associated with a share of Common Stock or any other class of capital stock or other security, shall be deducted.

(v)        "Adjustment Period" shall mean the period of five (5) consecutive trading days preceding, and including, the date as of which the Fair Market Value of a security is to be determined.

(vi)       "Valuation Date" with respect to an Extraordinary Distribution shall mean the date that is five (5) Business Days prior to the record date for such Extraordinary Distribution.

(vii)      "Plan" shall mean collectively the Corporation's Thrift and ESOP plans and its Thrift and ESOP Trust.

(G)       Whenever an adjustment to the Conversion Ratio and the related voting rights of the Class A Preferred Stock is required pursuant hereto, the Corporation shall forthwith deliver to the transfer agent(s) for the Common Stock and the Class A Preferred Stock and file with the Secretary of the Corporation, a statement signed by an officer of the Corporation stating the adjusted Conversion Ratio determined as provided herein, and the voting rights (as appropriately adjusted), of the Class A Preferred Stock.  Such statement shall set forth in reasonable detail such facts as shall be necessary to show the reason and the manner of computing such adjustment including any determination of Fair Market Value involved in such

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computation.  Promptly after each adjustment to the Conversion Ratio and the related voting rights of the Class A Preferred Stock, the Corporation shall mail a notice thereof and of the then prevailing Conversion Ratio to each holder of Class A Preferred Stock.

Section 10.  Ranking; Cancellation of Shares. 

(A)       The Class A Preferred Stock shall rank senior to the Common Stock as to the payment of dividends and senior to the Common Stock as to the distribution of assets on liquidation, dissolution and winding-up of the Corporation, and, unless otherwise provided in the Certificate of Incorporation, as the same may be amended, the Class A Preferred Stock shall rank on a parity with all other classes or series of the Corporation's preferred stock, as to payment of dividends and the distribution of assets on liquidation, dissolution or winding-up.

(B)       Any shares of Class A Preferred Stock acquired by the Corporation by reason of the conversion or redemption of such shares as provided hereby, or otherwise so acquired, shall be cancelled as shares of Class A Preferred Stock and restored to the status of authorized but unissued shares of preferred stock of the Corporation, undesignated as to classes or series, and may thereafter be reissued as part of a new class or series of such preferred stock as permitted by law.

Section 11.  Miscellaneous. 

(A)       All notices referred to herein shall be in writing, and all notices hereunder shall be deemed to have been given upon the earlier of receipt thereof or three (3) Business Days after the mailing thereof if sent by registered mail (unless first class mail shall be specifically permitted for such notice under the terms of this Exhibit A) with postage prepaid, addressed: (i) if to the Corporation, to its office at 5959 Las Colinas Boulevard, Irving, TX 75039 (Attention: Treasurer) or to the transfer agent (if any) for the Class A Preferred Stock or (ii) if to any holder of the Class A Preferred Stock or the Common Stock, as the case may be, to such holder at the address of such holder as listed in the stock record books of the Corporation (which may include the records of any transfer agent for the Class A Preferred Stock or the Common Stock, as the case may be) or (iii) to such other address as the Corporation shall have designated by notice similarly given.

(B)       In the event that, at any time as a result of an adjustment made pursuant to Section 8 or 9, the holder of any share of the Class A Preferred Stock upon thereafter surrendering such shares for conversion shall become entitled to receive any shares or other securities of the Corporation other than shares of Common Stock, the Conversion Ratio in respect of such other shares or securities so receivable upon conversion of shares of Class A Preferred Stock shall thereafter be adjusted, and shall be subject to further adjustment from time to time, in a manner and on terms as nearly equivalent as practicable to the provisions with respect to Common Stock contained in Sections 8 or 9, and the provisions of each of the other Sections hereof with respect to the Common Stock shall apply on like or similar terms to any such other shares or securities.  Any determination in good faith by the Corporation as to any adjustment of the Conversion Ratio pursuant to this Section 11 (B) shall be conclusive.

(C)       The Corporation shall pay any and all issuance, stock transfer and documentary stamp taxes that may be payable in respect of any issuance or delivery of shares of Class A Preferred Stock or Common Stock or other securities issued upon conversion of Class A

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Preferred Stock pursuant hereto or certificates representing such shares or securities.  The Corporation shall not, however, be required to pay any such tax which may be payable in respect of any transfer involved in the issuance or delivery of shares of Common Stock or other securities in a name other then that in which the shares of Class A Preferred Stock with respect to which such shares or other securities are issued or delivered were registered, or in respect of any payment to any person with respect to any such shares or securities other than a payment to the registered holder thereof, and shall not be required to make any such issuance, delivery or payment unless and until the person otherwise entitled to such issuance, delivery or payment has paid to the Corporation the amount of any such tax for issuance, transfer or documentary stamp taxes or has established, to the satisfaction of the Corporation, that such tax has been paid or is not payable.

(D)       In the event that a holder of shares of Class A Preferred Stock shall not by written notice designate the name in which (i) shares of Common Stock or (ii) any other securities in accordance with this Exhibit A, to be issued upon conversion of such shares should be registered or to whom payment upon redemption of shares of Class A Preferred Stock should be made or the address to which the certificate or certificates representing such shares, or such payment, should be sent, the Corporation shall be entitled to register such shares, and make such payment, in the name of the holder of such Class A Preferred Stock as shown on the records of the Corporation and to send the certificate or certificates representing such shares, or such payment, to the address of such holder shown on the records of the Corporation.

(E)       Unless otherwise provided in the Certificate of Incorporation, as the same may be amended, all payments of (x) dividends upon the shares of any class of stock and upon any other class of stock ranking on a parity with such first class of stock with respect to such dividends shall be made pro rata, so that amounts paid per share on such first class of stock and such other class of stock shall in all cases bear to each other the same ratio that the required dividends then payable per share on the shares of such first class of stock and such other class of stock bear to each other and (y) distributions on voluntary or involuntary dissolution, liquidation or winding-up or otherwise made upon the shares of any class of stock and upon any other class of stock ranking on a parity with such first class of stock with respect to such distributions shall be made pro rata, so that amounts paid per share on such first class of stock and such other class of stock shall in all cases bear to each other the same ratio that the required distributions then payable per share on the shares of such first class of stock and such other class of stock bear to each other.

(F)       The Corporation may appoint, and from time to time discharge and change, a transfer agent for the Class A Preferred Stock.  Upon any such appointment or discharge of a transfer agent, the Corporation shall send notice thereof by first class mail, postage prepaid, to each holder of record of Class A Preferred Stock.  So long as there is a transfer agent for a class of stock, a holder thereof shall give any notices to the Corporation required hereunder to the transfer agent at the address of the transfer agent last given by the Corporation.

(G)       If the Corporation and the holder so agree, any shares of Class A Preferred Stock or any shares of Common Stock into which the shares of Class A Preferred Stock shall be converted, may be uncertificated shares, provided  that the names of the holders of all uncertificated shares and the number of such shares held by each holder shall be registered at the offices of the Corporation or the transfer agent for such shares.  In the event that any shares shall be uncertificated, all references herein to the surrender or issuance of stock certificates shall have no application to such uncertificated shares.

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PART II

Class B Preferred Stock

1.         Designation and Issuance

(A)       The shares of such class shall be designated CLASS B PREFERRED STOCK (hereinafter referred to as “Class B Preferred Stock”) and the number of shares constituting such class shall be 165,800.  Such number of shares may be increased or decreased by resolution of the Board of Directors, but no such decrease shall reduce the number of shares of Class B Preferred Stock to a number less than that of the shares then outstanding plus the number of shares issuable upon exercise of any rights, options or warrants or upon conversion of outstanding securities issued by the Corporation.  All shares of Class B Preferred Stock redeemed or purchased by the Corporation shall be retired and shall be restored to the status of authorized but unissued shares of preferred stock without designation.

(B)       Shares of Class B Preferred Stock shall be issued only to a trustee or trustees acting on behalf of an employee stock ownership trust or plan or other employee benefit plan (“Plan”) of Mobil Corporation or Mobil Oil Corporation (collectively, “Mobil Oil”).  In the event of any sale, transfer or other disposition (hereinafter a “transfer”) of shares of Class B Preferred Stock to any person other than (x) any trustee or trustees of the Plan and (y) any pledgee of such shares acquiring such shares as security for any loan or loans made to the Plan or to any trustee or trustees acting on behalf of the Plan, the shares of Class B Preferred Stock so transferred, upon such transfer and without any further action by the Corporation or the holder shall be automatically converted into shares of the Common Stock (as defined in Section 10) at the Conversion Price (as hereinafter defined) and on the terms otherwise provided for the conversion of shares of Class B Preferred Stock into shares of Common Stock pursuant to Section 5 hereof and no such transferee shall have any of the voting powers, preferences and relative, participating, optional or special rights ascribed to shares of Class B Preferred Stock hereunder but, rather, only the powers and rights pertaining to the Common Stock into which such shares of Class B Preferred Stock shall be so converted, provided, however, that in the event of a foreclosure or other realization upon shares of Class B Preferred Stock pledged as security for any loan or loans made to the Plan or to the trustee or the trustees acting on behalf of the Plan, the pledged shares so foreclosed or otherwise realized upon shall (subject to the holder’s right of redemption set forth in Section 7(B) hereof) be automatically converted into shares of Common Stock at the Conversion Price and on the terms otherwise provided for conversions of shares of Class B Preferred Stock into shares of Common Stock pursuant to Section 5 hereof.  In the event of such a conversion, such transferee shall be treated for all purposes as the record holder of the shares of Common Stock into which the Class B Preferred Stock shall have been converted as of the date of such conversion.  Certificates representing shares of Class B Preferred Stock shall be legended to reflect such restrictions on transfer.  Notwithstanding the foregoing provisions of this Section 1, shares of Class B Preferred Stock (i) may be converted into shares of Common Stock as provided by Section 5 hereof and the shares of Common Stock issued upon such conversion may be transferred by the holder thereof as permitted by law and (ii) shall be redeemable by the Corporation upon the terms and conditions provided by Sections 6, 7 and 8 hereof.

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2.         Dividends and Distributions.

(A)(1)  Subject to the provisions for adjustment hereinafter set forth, the holders of shares of Class B Preferred Stock shall be entitled to receive, when and as declared by the Board of Directors out of funds legally available therefor, cash dividends (“Regular Preferred Dividends”) in an amount per share initially equal to $300 per share per annum, subject to adjustment from time to time as hereinafter provided, and no more, except as provided in Section 2(A)(2) (such amount, as adjusted from time to time, being hereinafter referred to as the “Regular Preferred Dividend Rate”), payable semiannually in arrears, one-half on the last day of February, and one-half on the last day of August of each year (each a “Dividend Payment Date”) to holders of record at the start of business on such Dividend Payment Date.  The first dividend payable on each share of Class B Preferred Stock shall accrue from the date of original issuance thereof, except that the first dividend payable on shares of Class B Preferred Stock issued on conversion of Mobil Corporation Series B ESOP Convertible Preferred Stock (“Mobil Series B Stock”) shall accrue and be cumulative from the last dividend payment date of the Mobil Series B Stock and shall include any arrearage on the Mobil Series B Stock.  Regular Preferred Dividends shall accrue on a daily basis, based on the Regular Preferred Dividend Rate in effect on such date, whether or not the Corporation shall have earnings or surplus at the time, computed on the basis of a 360-day year of 30-day months in case of any period less than a full semiannual period.  Accrued but unpaid Regular Preferred Dividends, shall cumulate as of the Dividend Payment Date on which they first become payable, but no interest shall accrue on accumulated but unpaid Regular Preferred Dividends. 

(2)        In the event that for any period of six (6) months preceding any Dividend Payment Date (each such period, a “Dividend Period”) the aggregate fair value (as determined by the Board of Directors) of all dividends and other distributions declared per share of Common Stock during such Dividend Period multiplied by the number of shares of Common Stock into which a share of Class B Preferred Stock was convertible on the appropriate dividend payment date for the Common Stock shall exceed the amount of the Regular Preferred Dividends accrued on a share of Class B Preferred Stock during such Dividend Period, the holders of shares of the Class B Preferred Stock shall be entitled to receive, when and as declared by the Board of Directors out of funds legally available therefor, cash dividends (the “Supplemental Preferred Dividends”) in an amount per share (with appropriate adjustments to reflect any stock split or combination of shares or other adjustment provided for in Section 9) equal to the amount of such excess up to but not exceeding (x) the product of twelve and one-half per cent (12.5%) times the average of the Fair Market Values of the number of shares of Common Stock into which a share of Class B Preferred Stock was convertible on the day next preceding the ex-dividend date for each such dividend and the distribution date for each such distribution on the Common Stock of the Corporation minus (y) such amount of accrued Regular Preferred Dividends.  The calculation of each Supplemental Preferred Dividend shall be subject to adjustment corresponding to the adjustments provided in Section 9 hereof.  Supplemental Preferred Dividends shall accrue and cumulate as of the close of each relevant Dividend Period and shall be payable on the Dividend Payment Date next following the close of any such Dividend Period, but no interest shall accrue on accumulated but unpaid Supplemental Preferred Dividends and no Supplemental Preferred Dividends shall accrue in respect of any period of less than six months.

(B)(1)  No full dividends shall be declared or paid or set apart for payment on any shares ranking, as to dividends, on a parity with or junior to the Class B Preferred Stock, for any

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period unless full cumulative dividends (which for all purposes of this resolution shall include Regular Preferred Dividends and Supplemental Preferred Dividends) have been or contemporaneously are declared and paid or declared and a sum sufficient for the payment thereof set apart for such payment on the Class B Preferred Stock for all Dividend Payment Dates occurring on or prior to the date of payment of such full dividends.  When dividends are not paid in full, as aforesaid, upon the shares of Class B Preferred Stock and any other shares ranking, as to dividends, on a parity with Class B Preferred Stock, all dividends declared upon shares of Class B Preferred Stock shall be declared pro rata so that the amount of dividends declared per share on Class B Preferred Stock and such other parity shares shall in all cases bear to each other the same ratio that accumulated dividends per share on the shares of Class B Preferred Stock and such other parity shares bear to each other.  Except as otherwise provided herein, holders of shares of Class B Preferred Stock shall not be entitled to any dividends, whether payable in cash, property or shares, in excess of full cumulative dividends, as herein provided, on Class B Preferred Stock.

(2)        So long as any shares of Class B Preferred Stock are outstanding, no dividend (other than dividends or distributions paid in shares of, or options, warrants or rights to subscribe for or purchase shares of, Common Stock or other shares ranking junior to Class B Preferred Stock as to dividends and upon liquidation and other than as provided in Section 2(B)(1)) shall be declared or paid or set aside for payment or other distribution declared or made upon the Common Stock or upon any other shares ranking junior to or on a parity with Class B Preferred Stock as to dividends or upon liquidation, nor shall any Common Stock or any other shares of the Company ranking junior to or on a parity with Class B Preferred Stock as to dividends or upon liquidation be redeemed, purchased or otherwise acquired for any consideration (or any moneys be paid to or made available for a sinking fund for the redemption of any such shares) by the Corporation (except by conversion into or exchange for shares of the Corporation ranking junior to Class B Preferred Stock as to dividends and upon liquidation) unless, in each case, the full cumulative dividends on all outstanding shares of Class B Preferred Stock shall have been paid.   

(3)        Any dividend payment made on shares of Class B Preferred Stock shall first be credited against the earliest accumulated but unpaid dividend due with respect to shares of Class B Preferred Stock.

3.         Liquidation Preference

(A)       In the event of any liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, before any payment or distribution of the assets of the Corporation (whether capital or surplus) shall be made to or set apart for the holders of any series or classes of stock of the Corporation ranking junior to Class B Preferred Stock upon liquidation, dissolution or winding-up, the holders of Class B Preferred Stock shall be entitled to receive the Liquidation Price (as hereinafter defined) per share in effect at the time of liquidation, dissolution or winding-up plus an amount equal to all dividends accrued (whether or not accumulated) and unpaid thereon to the date of final distribution to such holders, but such holders shall not be entitled to any further payments.  The Liquidation Price per share which holders of Class B Preferred Stock shall receive upon liquidation, dissolution or winding-up shall be $3,887.50, subject to adjustment as hereinafter provided.  If, upon any liquidation, dissolution or winding-up of the Corporation, the assets of the Corporation, or proceeds thereof, distributable among the holders of Class B Preferred Stock shall be insufficient to pay in full the preferential

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amount aforesaid and liquidating payments on any other shares ranking as to liquidation, dissolution or winding-up, on a parity with Class B Preferred Stock, then such assets, or the proceeds thereof, shall be distributed among the holders of Class B Preferred Stock and any such other shares ratably in accordance with the respective amounts which would be payable on such shares of Class B Preferred Stock and any such other shares if all amounts payable thereon were paid in full.  For the purposes of this Section 3, a consolidation or merger of the Corporation with one or more corporations shall not be deemed to be a liquidation, dissolution or winding-up, voluntary and involuntary.

(B)       Subject to the rights of the holders of shares of any series or class or classes of stock ranking on a parity with or prior to Class B Preferred Stock upon liquidation, dissolution or winding-up, upon any liquidation, dissolution or winding-up of the Corporation, after payment shall have been made in full to the holders of Class B Preferred Stock as provided in this Section 3, but not prior thereto, any other series or class or classes of stock ranking junior to Class B Preferred Stock upon liquidation, dissolution or winding-up shall, subject to the respective terms and provisions (if any) applying thereto, be entitled to receive any and all assets remaining to be paid or distributed, and the holders of Class B Preferred Stock shall not be entitled to share therein.

4.         Ranking and Voting of Shares.

(A)       Any shares of the Corporation shall be deemed to rank:

(1)        prior to Class B Preferred Stock as to dividends or as to distribution of assets upon liquidation, dissolution or winding-up, if the holders of such class shall be entitled to the receipt of dividends or of amounts distributable upon liquidation, dissolution or winding-up, as the case may be, in preference or priority to the holders of Class B Preferred Stock,

(2)        on a parity with Class B Preferred Stock as to dividends or as to distribution of assets upon liquidation, dissolution or winding-up, whether or not the dividend rates, dividend payment dates, or redemption or liquidation prices per share thereof be different from those of Class B Preferred Stock, if the holders of such class of stock and Class B Preferred Stock shall be entitled to the receipt of dividends or of amounts distributable upon liquidation, dissolution or winding-up, as the case may be, in proportion to their respective dividend or liquidation amounts, as the case may be, without preference or priority one over the other, and

(3)        junior to Class B Preferred Stock as to dividends or as to the distribution of assets upon liquidation, dissolution or winding-up, if such shares shall be Common Stock or if the holders of Class B Preferred Stock shall be entitled to receipt of dividends or of amounts distributable upon liquidation, dissolution or winding-up, as the case may be, in preference or priority to the holders of such shares. Unless otherwise provided in the Restated Certificate of Incorporation of the Corporation, as the same may be amended, including an amendment relating to any subsequent class or series of preferred stock, the Class B Preferred Stock shall rank junior to all classes or series of the Corporation’s preferred stock as to dividends and the distribution of assets upon liquidation, dissolution or winding-up.

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(B)       The holders of shares of Class B Preferred Stock shall have the following voting rights:

(1)        The holders of Class B Preferred Stock shall be entitled to vote on all matters submitted to a vote of the shareholders of the Corporation, voting together with the holders of Common Stock as one class.  The holder of each share of Class B Preferred Stock shall be entitled to a number of votes equal to the number of shares of Common Stock into which such Class B Preferred Stock could be converted on the record date for determining the shareholders entitled to vote; it being understood that whenever the “Conversion Price” (as defined in Section 5 hereof) is adjusted as provided in Section 9 hereof, the number of votes of the Class B Preferred Stock shall also be correspondingly adjusted.

(2)        Except as otherwise required by law or set forth herein, holders of Class B Preferred Stock shall have no special voting rights and their consent shall not be required (except to the extent they are entitled to vote with holders of Common Stock as set forth herein) for the taking of any corporate action, including the issuance of any preferred stock now or hereafter authorized, provided, however, that the vote of at least 66-2/3% of the outstanding shares of Class B Preferred Stock, voting separately as a class, shall be necessary to approve any alteration, amendment or repeal of any provision of the Restated Certificate of Incorporation or any alteration, amendment or repeal of any provision of the resolutions relating to the designation, preferences and rights of Class B Preferred Stock (including any such alteration, amendment or repeal effected by any merger or consolidation in which the Corporation is the surviving or resulting corporation), if such amendment, alteration or repeal would alter or change the powers, preferences, or special rights of the Class B Preferred Stock so as to affect them adversely.

5.         Conversion into Common Stock.

(A)       A holder of shares of Class B Preferred Stock shall be entitled, at any time prior to the close of business on the date fixed for redemption of such shares pursuant to Sections 6, 7 or 8 hereof, to cause any or all of such shares to be converted into shares of Common Stock.  The number of shares of Common Stock into which each share of the Class B Preferred Stock may be converted shall be determined by dividing the Liquidation Price in effect at the time of conversion by the Conversion Price (as hereinafter defined) in effect at the time of conversion.  The Conversion Price per share at which shares of Common Stock shall be initially issuable upon conversion of any shares of Class B Preferred Stock shall be $29.447411subject to adjustment as hereinafter provided; that is, a conversion rate initially equivalent to 132.015 shares of Common Stock for each share of Class B Preferred Stock, which is subject to adjustment as hereinafter provided.

(B)       Any holder of shares of Class B Preferred Stock desiring to convert such shares into shares of Common Stock shall surrender, if certificated, the certificate or certificates representing the shares of Class B Preferred Stock being converted, duly assigned or endorsed for transfer to the Corporation (or accompanied by duly executed stock powers relating thereto), or if uncertificated, a duly executed stock power relating thereto, at the principal executive office of the Corporation or the offices of the transfer agent for the Class B Preferred Stock or such office or offices in the continental United States of an agent for conversion as may from time to time be designated by notice to the holders of the Class B Preferred Stock by the Corporation or the transfer agent for the Class B Preferred Stock, accompanied by written notice of conversion.  Such notice of conversion shall specify (i) the number of shares of Class B Preferred Stock to be converted and the name or names in which such holder wishes the Common Stock and any

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shares of Class B Preferred Stock not to be so converted to be issued, and (ii) the address to which such holder wishes delivery to be made of a confirmation of such conversion, if uncertificated, or any new certificate which may be issued upon such conversion if certificated.

(C)       Upon surrender, if certificated, of a certificate representing a share or shares of Class B Preferred Stock for conversion, or if uncertificated, of a duly executed stock power relating thereto, the Corporation shall issue and send by hand delivery (with receipt to be acknowledged) or by first class mail, postage prepaid, to the holder thereof or to such holder’s designee, at the address designated by such holder, if certificated, a certificate or certificates for, or if uncertificated, confirmation of, the number of shares of Common Stock to which such holder shall be entitled upon conversion.  In the event that there shall have been surrendered shares of Class B Preferred Stock, only part of which are to be converted, the Corporation shall issue and deliver to such holder or such holder’s designee, if certificated, a new certificate or certificates representing the number of shares of Class B Preferred Stock which shall not have been converted, or if uncertificated, confirmation of the number of shares of Class B Preferred Stock which shall not have been converted.

(D)       The issuance by the Corporation of shares of Common Stock upon a conversion of shares of Class B Preferred Stock into shares of Common Stock made at the option of the holder thereof shall be effective as of the earlier of (i) the delivery to such holder or such holder’s designee of the certificates representing the shares of Common Stock issued upon conversion thereof if certificated or confirmation if uncertificated or (ii) the commencement of business on the second business day after the surrender of the certificate or certificates, if certificated, or a duly executed stock power, if uncertificated, for the shares of Class B Preferred Stock to be converted.  On and after the effective date of conversion, the person or persons entitled to receive Common Stock issuable upon such conversion shall be treated for all purposes as the record holder or holders of such shares of Common Stock, but no allowance or adjustment shall be made in respect of dividends payable to holders of Common Stock of record on any date prior to such effective date.  The Corporation shall not be obligated to pay any dividends which shall have been declared and shall be payable to holders of shares of Class B Preferred Stock on a Dividend Payment Date if such Dividend Payment Date for such dividend shall be on or subsequent to the effective date of conversion of such shares.

(E)       The Corporation shall not be obligated to deliver to holders of Class B Preferred Stock any fractional share or shares of Common Stock issuable upon any conversion of such shares of Class B Preferred Stock, but in lieu thereof may make a cash payment in respect thereof in any manner permitted by law.

(F)       The Corporation shall at all times reserve and keep available out of its authorized and unissued Common Stock or treasury Common Stock, solely for issuance upon the conversion of shares of Class B Preferred Stock as herein provided, such number of shares of Common Stock as shall from time to time be issuable upon the conversion of all the shares of Class B Preferred Stock then outstanding.

6.         Redemption at the Option of the Corporation.

                        (A)       The Class B Preferred Stock shall be redeemable, in whole or in part, at the option of the Corporation, out of funds legally available therefor, at any time after November 22, 1999 at 100% of the Liquidation Price per share in effect on the date fixed for redemption, plus an amount equal to all accrued (whether or not accumulated) and unpaid dividends thereon

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to the date fixed for redemption.  The Class B Preferred Stock shall be redeemable, in whole or in part, out of funds legally available therefor, on or before November 22, 1999 only if permitted by Section 6 (C) or (D) at a price per share equal to, (i) if pursuant to Section 6(C), the redemption price set forth therein, or (ii) if pursuant to Section 6(D), 100.775% of the Liquidation Price in effect on the date fixed for redemption, plus, in each case, an amount equal to all accrued (whether or not accumulated) and unpaid dividends thereon to the date fixed for redemption.  Payment of the redemption price shall be made by the Corporation in cash or shares of Common Stock, or a combination thereof, as permitted by Section 6(E).  From and after the date fixed for redemption, dividends on shares of Class B Preferred Stock called for redemption will cease to accrue, such shares will no longer be deemed to be outstanding and all rights in respect of such shares of the Corporation shall cease, except for the right to receive the redemption price.  If less than all of the outstanding shares of Class B Preferred Stock are to be redeemed, the Corporation shall either redeem a portion of the shares of each holder determined pro rata based on the number of shares held by each holder or shall select the shares to be redeemed by lot, as may be determined by the Board of Directors of the Corporation.

(B)       Unless otherwise required by law, notice of redemption will be sent to the holders of Class B Preferred Stock at the address shown on the books of the Corporation or any transfer agent for Class B Preferred Stock by first class mail, postage prepaid, mailed not less than twenty (20) days nor more than sixty (60) days prior to the redemption date.  Each notice shall state:  (i) the redemption date; (ii) the total number of shares of the Class B Preferred Stock to be redeemed and, if fewer than all the shares held by such holder are to be redeemed, the number of such shares to be redeemed from such holder; (iii) the redemption price; (iv) the place or places where certificates, if certificated, for such shares are to be surrendered for payment of the redemption price; (v) that dividends on the shares to be redeemed will cease to accrue on such redemption date; (vi) the conversion rights of the shares to be redeemed, the period within which such conversion rights may be exercised, and the Conversion Price and number of shares of Common Stock issuable upon conversion of a share of Class B Preferred Stock at the time.  Upon surrender of the certificates, if certificated, for any shares so called for redemption, or upon the date fixed for redemption if uncertificated such shares if not previously converted shall be redeemed by the Corporation on the date fixed for redemption and at the redemption price set forth in this Section 6.

(C)       In the event (i) of a change in the federal tax law or regulations of the United States of America or of an interpretation or application of such law or regulations or of a determination by a court of competent jurisdiction, which in any case has the effect of precluding the Corporation from claiming (other than for purposes of calculating any alternative minimum tax) any of the tax deductions for dividends paid on the Class B Preferred Stock when such dividends are used as provided under Section 404(k)(2) of the Internal Revenue Code of 1986, as amended (the “Code”) as in effect on the date shares of Class B Preferred Stock are initially issued, or (ii) that the Corporation certifies to the holders of the Class B Preferred Stock that the Corporation has determined in good faith that the Plan either is not qualified within the meaning of Section 401(a) of the Code or is not an “employee stock ownership plan” within the meaning of 4975(e)(7) of the Code, the Corporation may, in its sole discretion and notwithstanding anything to the contrary in Section 6(A), at any time within one year of the occurrence of such event, elect either to (a) redeem any or all of such Class B Preferred Stock for cash or, if the Corporation so elects, in shares of Common Stock, or a combination of such shares of Common Stock and cash, as permitted by Section 6(B), at a redemption price equal to the higher of (x) the

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Liquidation Price per share on the date fixed for redemption or (y) the Fair Market Value (as defined in Section 9(G)(2)) of the number of shares of Common Stock into which each share of Class B Preferred Stock is convertible at the time the notice of such redemption is given, plus in either case an amount equal to accrued (whether or not accumulated) and unpaid dividends thereon to the date fixed for redemption, or (b) exchange any or all of such shares of Class B Preferred Stock for securities of comparable value (as determined by an independent appraiser) that constitute “qualifying employer securities” with respect to a holder of Class B Preferred Stock within the meaning of Section 409(1) of the Code and Section 407(d)(5) of the Employment Retirement Income Security Act of 1974, as amended (“ERISA”) or any successor provisions of law.

(D)       Notwithstanding anything to the contrary in Section 6(A), in the event that the Employees Savings Plan of Mobil Oil is terminated or the Employee Stock Ownership Plan incorporated therein is terminated or eliminated from such Plan, the Corporation may, in its sole discretion, call for redemption of any or all of the then outstanding Class B Preferred Stock at a redemption price calculated on the basis of the redemption prices provided in Section 6(A), increased by 50% of the amount thereof in excess of 100% of the Liquidation Price in effect on the date fixed for redemption.

(E)       The Corporation, at its option, may make payment of the redemption price required upon redemption of shares of Class B Preferred Stock in cash or in shares of Common Stock, or in a combination of such shares and cash, any such shares of Common Stock to be valued for such purpose at their Fair Market Value (as defined in Section 9(G)(2)); provided, however, that in calculating their Fair Market Value the Adjustment Period shall be deemed to be the five (5) consecutive trading days preceding the date of redemption.

7.         Redemption at the Option of the Holder.

(A)       Unless otherwise provided by law, shares of Class B Preferred Stock shall be redeemed by the Corporation out of funds legally available therefor for cash or, if the Corporation so elects, in shares of Common Stock, or a combination of such shares and cash, any such shares of Common Stock to be valued for such purpose as provided by Section 6(E), at a redemption price equal to the higher of (x) the Liquidation Price per share in effect on the date fixed for redemption or (y) the Fair Market Value of the number of shares of Common Stock into which each share of Class B Preferred Stock is convertible at the time the notice of such redemption is given plus in either case an amount equal to accrued (whether or not accumulated) and unpaid dividends thereon to the date fixed for redemption, at the option of the holder, at any time and from time to time upon notice to the Corporation given not less than five (5) business days prior to the date fixed by the holder in such notice of redemption, when and to the extent necessary for such holder to provide for distributions required to be made under, or to satisfy an investment election provided to participants in accordance with, the Employee Stock Ownership Plan incorporated in the Employees Savings Plan of Mobil Oil, or any successor plan or when the holder elects to redeem shares of Class B Preferred Stock in respect of any Regular or Supplemental Preferred Dividend (a “Dividend Redemption”).  In the case of any Dividend Redemption, such holder shall give the notice specified above within five (5) business days after the related Dividend Payment Date and such redemption shall be effective as to such number of shares of Class B Preferred Stock as shall equal (x) the aggregate amount of such Regular or Supplemental Preferred Dividend with respect to shares of Class B Preferred Stock allocated or credited to the accounts of participants in the Employee Stock Ownership Plan incorporated in the Employees Savings Plan of Mobil Oil, or any successor plan divided by (y) the redemption price specified above.

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(B)       Shares of Class B Preferred Stock shall be redeemed by the Corporation out of funds legally available therefor for cash or, if the Corporation so elects, in shares of Common Stock, or a combination of such shares of Common Stock and cash, any such shares of Common Stock to be valued for such purpose as provided by Section 6(E), at a redemption price equal to the Liquidation Price plus an amount equal to accrued and unpaid dividends thereon to the date fixed for redemption, at the option of the holder, at any time and from time to time upon notice to the Corporation given not less than five (5) business days prior to the date fixed by the holder in such notice for such redemption, upon certification by such holder to the Corporation of the following events:  (i) when and to the extent necessary for such holder to make any payments of principal, interest or premium due and payable (whether as scheduled, upon acceleration or otherwise) upon any obligations of the trust established under the Employee Stock Ownership Plan incorporated in the Employees Savings Plan of Mobil Oil in connection with the acquisition of Class B Preferred Stock or any indebtedness, expenses or costs incurred by the holder for the benefit of the Plan; or (ii) when and if it shall be established to the satisfaction of the holder that the Plan has not initially been determined by the Internal Revenue Service to be qualified as a stock bonus plan and an employee stock ownership plan within the meaning of Sections 401(a) or 4975(e)(7) of the Code, respectively.

8.         Consolidation, Merger, etc.

(A)       In the event that the Corporation shall consummate any consolidation or merger or similar transaction, however named, pursuant to which the outstanding shares of Common Stock are by operation of law exchanged solely for or changed, reclassified or converted solely into shares of any successor or resulting company (including the Corporation) that constitute “qualifying employer securities” that are common stock with respect to a holder of Class B Preferred Stock within the meanings of Section 409(1) of the Code and Section 407(d)(5) of ERISA, or any successor provision of law, and, if applicable, for a cash payment in lieu of fractional shares, if any, then, in such event, the terms of such consolidation or merger or similar transaction shall provide that the shares of Class B Preferred Stock of such holder shall be converted into or exchanged for and shall become preferred shares of such successor or resulting company, having in respect of such company insofar as possible the same powers, preferences and relative, participating, optional or other special rights (including the redemption rights provided by Sections 6, 7, and 8 hereof), and the qualifications, limitations or restrictions thereon, that the Class B Preferred Stock had immediately prior to such transaction; provided, however, that after such transaction each share of stock into which the Class B Preferred Stock is so converted or for which it is exchanged shall be convertible, pursuant to the terms and conditions provided by Section 5 hereof, into the number and kind of qualifying employer securities receivable by a holder of the number of shares of Common Stock into which such shares of Class B Preferred Stock could have been converted pursuant to Section 5 hereof immediately prior to such transaction and provided, further, that if by virtue of the structure of such transaction, a holder of Common Stock is required to make an election with respect to the nature and kind of consideration to be received in such transaction, which election cannot practicably be made by the holders of the Class B Preferred Stock, then such election shall be deemed to be solely for “qualifying employer securities” (together, if applicable, with a cash payment in lieu of fractional shares) with the effect provided above on the basis of the number

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and kind of qualifying employer securities receivable by a holder of the number of shares of Common Stock into which the shares of Class B Preferred Stock could have been converted pursuant to Section 5 hereof immediately prior to such transaction (it being understood that if the kind or amount of qualifying employer securities receivable in respect of each share of Common Stock upon such transaction is not the same for each such share, then the kind and amount of qualifying employer securities deemed to be receivable in respect of each share of Common Stock for purposes of this proviso shall be the kind and amount so receivable per share of Common Stock by a plurality of such shares).  The rights of the Class B Preferred Stock as preferred shares of such successor resulting company shall successively be subject to adjustments pursuant to Section 9 hereof after any such transaction as nearly equivalent to the adjustments provided for by such Section prior to such transaction.  The Corporation shall not consummate any such merger, consolidation or similar transaction unless all the terms of this Section 8(A) are complied with.

(B)       In the event that the Corporation shall consummate any consolidation or merger or similar transaction, however named, pursuant to which the outstanding shares of Common Stock are by operation of law exchanged for or changed, reclassified or converted into other shares or securities or cash or any other property, or any combination thereof, other than any such consideration which is constituted solely of qualifying employer securities that are common stock (as referred to in Section 8(A)) and cash payments, if applicable, in lieu of fractional shares, outstanding shares of Class B Preferred Stock shall, without any action on the part of the Corporation or any holder thereof (but subject to Section 8(C)), be automatically converted immediately prior to the consummation of such merger, consolidation or similar transaction into shares of Common Stock at the conversion rate then in effect so that each share of Class B Preferred Stock shall, by virtue of such transaction and on the same terms as apply to the holders of Common Stock, be converted into or exchanged for the aggregate amount of shares, securities, cash or other property (payable in like kind) receivable by a holder of the number of shares of Common Stock into which such shares of Class B Preferred Stock could have been converted immediately prior to such transaction if such holder of Common Stock failed to exercise any rights of election as to the kind or amount of shares, securities, cash or other property receivable upon such transaction (provided that, if the kind or amount of shares, securities, cash or other property receivable upon such transaction is not the same for each non-electing share, then the kind and amount of shares, securities, cash or other property receivable upon such transaction for each non-electing share shall be the kind and amount so receivable per share by a plurality of non-electing shares).

(C)       In the event the Corporation shall enter into any agreement providing for any consolidation or merger or similar transaction described in Section 8(B), then the Corporation shall as soon as practicable thereafter (and in any event at least ten (10) business days before consummation of such transaction) give notice of such agreement and the material terms thereof to each holder of Class B Preferred Stock and each such holder shall have the right to elect, by written notice to the Corporation, to receive, upon consummation of such transaction (if and when such transaction is consummated), out of funds legally available therefor, from the Corporation or the successor of the Corporation, in redemption and retirement of such Class B Preferred Stock, in lieu of any cash or other securities which such holder would otherwise be entitled to receive under Section 8(B) hereof, a cash payment equal to the redemption price specified in Section 6(A) in effect on the date of the consummation of such transaction plus an amount equal to all accrued (whether or not accumulated) and unpaid dividends.  No such notice

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of redemption shall be effective unless given to the Corporation prior to the close of business of the fifth business day prior to consummation of such transaction, unless the Corporation or the successor of the Corporation shall waive such prior notice, but any notice of redemption so given prior to such time may be withdrawn by notice of withdrawal given to the Corporation prior to the close of business on the fifth business day prior to consummation of such transaction.

9.         Anti-dilution Adjustments.

                        (A)(1)  Subject to the provisions of Section 9(E), in the event the Corporation shall, at any time or from time to time while any of the shares of the Class B Preferred Stock are outstanding, (i) pay a dividend or make a distribution in respect of the Common Stock in shares of Common Stock or (ii) subdivide the outstanding shares of Common Stock into a greater number of shares, in each case whether by reclassification of shares, recapitalization of the Corporation (excluding a recapitalization or reclassification effected by a merger or consolidation to which Section 8 hereof applies) or otherwise, then, in such event, the Board of Directors shall, to the extent legally permissible, declare a dividend in respect of the Class B Preferred Stock in shares of Class B Preferred Stock (a “Special Dividend”) in such a manner that a holder of Class B Preferred Stock will become a holder of that number of shares of Class B Preferred Stock equal to the product of the number of such shares held prior to such event times a fraction (the “Sec. 9(A) Non-Dilutive Share Fraction”), the numerator of which is the number of shares of Common Stock outstanding immediately after such event and the denominator of which is the number of shares of Common Stock outstanding immediately before such event.  A Special Dividend declared pursuant to this Section 9(A)(1) shall be effective, upon payment of such dividend or distribution in respect of the Common Stock, as of the record date for the determination of shareholders entitled to receive such dividend or distribution (on a retroactive basis), and in the case of a subdivision shall become effective immediately as of the effective date thereof.  Concurrently with the declaration of the Special Dividend pursuant to this Section 9(A)(1), the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate of all shares of Class B Preferred Stock shall be adjusted by dividing the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate, respectively, in effect immediately before such event by the Sec. 9(A) Non-Dilutive Share Fraction.

(2)        The Corporation and the Board of Directors shall each use its best efforts to take all necessary steps or to take all actions as are reasonably necessary or appropriate for declaration of the Special Dividend provided in Section 9(A)(1) but shall not be required to call a special meeting of shareholders in order to implement the provisions thereof.  If for any reason the Board of Directors is precluded from giving full effect to the Special Dividend provided in Section 9(A)(1), then no such Special Dividend shall be declared, but instead the Conversion Price shall automatically be adjusted by dividing the Conversion Price in effect immediately before the event by the Sec. 9(A) Non-Dilutive Share Fraction and the Liquidation Price and the Regular Preferred Dividend Rate will not be adjusted.  An adjustment to the Conversion Price made pursuant to this Section 9(A)(2) shall be given effect, upon payment of such a dividend or distribution, as of the record date for the determination of holders entitled to receive such dividend or distribution (on a retroactive basis), and in the case of a subdivision shall become effective immediately as of the effective date thereof.  If subsequently the Board of Directors is able to give full effect to the Special Dividend as provided in Section 9(A)(1), then such Special Dividend will be declared and other adjustments will be made in accordance with the provisions of Section 9(A)(1) and the adjustment in the Conversion Price as provided in this Section 9(A)(2) will automatically be reversed and nullified prospectively.

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(3)        Subject to the provisions of Section 9(E) hereof, in the event the Corporation shall, at any time or from time to time while any of the shares of the Class B Preferred Stock are outstanding, combine the outstanding shares of Common Stock into a lesser number of shares, whether by reclassification of shares, recapitalization of the Corporation (excluding a recapitalization or reclassification effected by a merger, consolidation or other transaction to which Section 8 hereof applies) or otherwise, then, in such event, the Conversion Price shall automatically be adjusted by dividing the Conversion Price in effect immediately before such event by the Sec. 9(A) Non-Dilutive Share Fraction and the Liquidation Price and the Regular Preferred Dividend Rate will not be adjusted.  An adjustment to the Conversion Price made pursuant to this Section 9(A)(3) shall be given effect immediately as of the effective date of such combination.

(B)(1)  Subject to the provisions of Section 9(E), in the event the Corporation shall, at any time or from time to time while any of the shares of Class B Preferred Stock are outstanding issue to holders of shares of Common Stock as a dividend or distribution, including by way of reclassification of shares or a recapitalization of the Corporation, any right or warrant to purchase shares of Common Stock (but not including as a right or warrant for this purpose any security convertible into or exchangeable for shares of Common Stock) for a consideration having a Fair Market Value (as defined in Section 9 (G)(2) hereof) per share less than the Fair Market Value of a share of Common Stock on the date of issuance of such right or warrant, then, in such event, the Board of Directors shall, to the extent legally permissible, declare a Special Dividend in such a manner that a holder of Class B Preferred Stock will become a holder of that number of shares of Class B Preferred Stock equal to the product of the number of such shares held prior to such event times a fraction (the “Sec. 9(B) Non-Dilutive Share Fraction”), the numerator of which is the number of shares of Common Stock outstanding immediately before such issuance of rights or warrants plus the maximum number of shares of Common Stock that could be acquired upon exercise in full of all such rights and warrants and the denominator of which is the number of shares of Common Stock outstanding immediately before such issuance of warrants or rights plus the number of shares of Common Stock which could be purchased at the Fair Market Value of a share of Common Stock at the time of such issuance for the maximum aggregate consideration payable upon exercise in full of all such rights and warrants.  A Special Dividend declared pursuant to this Section 9(B)(1) shall be effective upon such issuance of rights or warrants.  Concurrently with the declaration of the Special Dividend pursuant to this Section 9(B)(1), the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate of all shares of Class B Preferred Stock shall be adjusted by dividing the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate, respectively, in effect immediately before such event by the Sec. 9(B) Non-Dilutive Share Fraction.

(2)        The Corporation and the Board of Directors shall each use its best efforts to take all necessary steps or to take all actions as are reasonably necessary or appropriate for declaration of the Special Dividend provided in Section 9(B)(1) but shall not be required to call a special meeting of shareholders in order to implement the provisions thereof.  If for any reason the Board of Directors is precluded from giving full effect to the Special Dividend provided in Section 9(B)(1), then no such Special Dividend shall be declared, but instead the Conversion Price shall automatically be adjusted by dividing the Conversion Price in effect immediately

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before the event by the Sec. 9(B) Non-Dilutive Share Fraction and the Liquidation Price and the Preferred Dividend Rate will not be adjusted.  An adjustment to the Conversion Price made pursuant to this Section 9(B)(2) shall be given effect upon issuance of rights or warrants.  If subsequently the Board of Directors is able to give full effect to the Special Dividend as provided in Section 9(B)(1), then such Special Dividend will be declared and other adjustments will be made in accordance with the provisions of Section 9(B)(1) and the adjustment in the Conversion Price as provided in this Section 9(B)(2) will automatically be reversed and nullified prospectively.

(C)(1)(i)           Subject to the provisions of Section 9(E), in the event the Corporation shall, at any time or from time to time while any of the shares of Class B Preferred Stock are outstanding, issue, sell or exchange shares of Common Stock (other than pursuant to (x) any right or warrant to purchase or acquire shares of Common Stock (including as such a right or warrant any security convertible into or exchangeable for shares of Common Stock),  or (y) any employee or director incentive, compensation or benefit plan or arrangement of the Corporation or any subsidiary of the Corporation heretofore or hereafter adopted) at a purchase price per share less than the Fair Market Value of a share of Common Stock on the date of such issuance, sale or exchange, then, in such event, the Board of Directors shall, to the extent legally permissible, declare a Special Dividend in such a manner that a holder of Class B Preferred Stock will become the holder of that number of shares of Class B Preferred Stock equal to the product of the number of such shares held prior to such event times a fraction (the “Sec. 9(C)(1)(i) Non-Dilutive Share Fraction”), the numerator of which is the number of shares of Common Stock outstanding immediately before such issuance, sale or exchange plus the number of shares of Common Stock so issued, sold or exchanged and the denominator of which is the number of shares of Common Stock outstanding immediately before such issuance, sale or exchange plus the number of shares of Common Stock which could be purchased at the Fair Market Value of a share of Common Stock at the time of such issuance, sale or exchange for the maximum aggregate consideration paid therefor.

(ii)        In the event that the Corporation shall, at any time or from time to time while any Class B Preferred Stock is outstanding, issue, sell or exchange any right or warrant to purchase or acquire shares of Common Stock (including as such a right or warrant any security convertible into or exchangeable for shares of Common Stock other than pursuant to (x) any employee or director incentive, compensation or benefit plan or arrangement of the Corporation or any subsidiary of the Corporation heretofore or hereafter adopted and (y) any dividend or distribution on shares of Common Stock contemplated in Section 9(A)(1)) for a consideration having a Fair Market Value, on the date of such issuance, sale or exchange, less than the Non-Dilutive Amount (as defined in Section 9(G)(3) hereof), then, in such event, the Board of Directors shall, to the extent legally permissible, declare a Special Dividend in such a manner that a holder of Class B Preferred Stock will become the holder of that number of shares of Class B Preferred Stock equal to the product of the number of such shares held prior to such event times a fraction (the “Sec. 9(C)(1)(ii) Non-Dilutive Share Fraction”), the numerator of which is the number of shares of Common Stock outstanding immediately before such issuance of rights or warrants plus the maximum number of shares of Common Stock that could be acquired upon exercise in full of all such rights and warrants and the denominator of which is the number of shares of Common Stock outstanding immediately before such issuance of rights or warrants plus the number of shares of Common Stock which could be purchased at the Fair Market Value of a share of Common Stock at the time of such issuance for the total of (x) the maximum

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aggregate consideration payable at the time of the issuance, sale or exchange of such right or warrant and (y) the maximum aggregate consideration payable upon exercise in full of all such rights or warrants.

(iii)       A Special Dividend declared pursuant to this Section 9(C)(1) shall be effective upon the effective date of such issuance, sale or exchange.  Concurrently with the declaration of the Special Dividend pursuant to this Section 9(C)(1), the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate of all shares of Class B Preferred Stock shall be adjusted by dividing the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate, respectively, in effect immediately before such event by the Sec. 9(C)(1)(i) or Sec. 9(C)(1)(ii) Non-Dilutive Share Fraction, as the case may be.

(2)        The Corporation and the Board of Directors shall each use its best efforts to take all necessary steps or to take all actions as are reasonably necessary or appropriate for declaration of the Special Dividend provided in Section 9(C)(1)(i) or (ii) but shall not be required to call a special meeting of shareholders in order to implement the provisions thereof.  If for any reason the Board of Directors is precluded from giving full effect to any Special Dividend provided in Section 9(C)(1), then no such Special Dividend shall be declared, but instead the Conversion Price shall automatically be adjusted by dividing the Conversion Price in effect immediately before the event by the Sec. 9(C)(1)(i) or Sec. 9(C)(1)(ii) Non-Dilutive Share Fraction, as the case may be, and the Liquidation Price and the Regular Preferred Dividend Rate will not be adjusted.  An adjustment to the Conversion Price made pursuant to this Section 9(C)(2) shall be given effect upon the effective date of such issuance, sale or exchange.  If subsequently the Board of Directors is able to give full effect to the Special Dividend as provided in Section 9(C)(1), then such Special Dividend will be declared and other adjustments will be made in accordance with the provisions of Section 9(C)(1) and the adjustment in the Conversion Price as provided in this Section 9(C)(2) will automatically be reversed and nullified prospectively.

(D)(1)  Subject to the provisions of Section 9(E), in the event the Corporation shall, at any time or from time to time while any of the shares of Class B Preferred Stock are outstanding, make an Extraordinary Distribution (as defined in Section 9(G)(1) hereof) in respect of the Common Stock, whether by dividend, distribution, reclassification of shares or recapitalization of the Corporation (including capitalization or reclassification effected by a merger or consolidation to which Section 8 hereof does not apply) or effect a Pro Rata Repurchase (as defined in Section 9(G)(4) hereof) of Common Stock, then, in such event, the Board of Directors shall, to the extent legally permissible, declare a Special Dividend in such a manner that a holder of Class B Preferred Stock will become a holder of that number of shares of Class B Preferred Stock equal to the product of the number of such shares held prior to such event times a fraction (the “Sec. 9(D) Non-Dilutive Share Fraction”), the numerator of which is the product of (a) the number of shares of Common Stock outstanding immediately before such Extraordinary Distribution or Pro Rata Repurchase minus, in the case of a Pro Rata Repurchase, the number of shares of Common Stock repurchased by the Corporation multiplied by (b) the Fair Market Value of a share of Common Stock on the day before the ex-dividend date with respect to an Extraordinary Distribution which is paid in cash and on the distribution date with respect to an Extraordinary Distribution which is paid other than in cash, or on the applicable expiration date (including all extensions thereof) of any tender offer which is a Pro Rata Repurchase or on the date of purchase with respect to any Pro Rata Repurchase which is not a

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tender offer, as the case may be, and the denominator of which is (i) the product of (x) the number of shares of Common Stock outstanding immediately before such Extraordinary Distribution or Pro Rata Repurchase multiplied by (y) the Fair Market Value of a share of Common Stock on the day before the ex-dividend date with respect to an Extraordinary Distribution which is paid in cash and on the distribution date with respect to an Extraordinary Distribution which is paid other than in cash, or on the applicable expiration date (including all extensions thereof) of any tender offer which is a Pro Rata Repurchase, or on the date of purchase with respect to any Pro Rata Repurchase which is not a tender offer, as the case may be, minus (ii) the Fair Market Value of the Extraordinary Distribution or the aggregate purchase price of the Pro Rata Repurchase, as the case may be.  The Corporation shall send each holder of Class B Preferred Stock (i) notice of its intent to make an Extraordinary Distribution and (ii) notice of any offer by the Corporation to make a Pro Rata Repurchase, in each case at the same time as, or as soon as practicable after, such offer is first communicated to holders of Common Stock or, in the case of an Extraordinary Distribution, the announcement of a record date in accordance with the rules of any stock exchange on which the Common Stock is listed or admitted to trading.  Such notice shall indicate the intended record date and the amount and nature of such dividend or distribution, or the number of shares subject to such offer for a Pro Rata Repurchase and the purchase price payable by the Corporation pursuant to such offer, as well as the Conversion Price and the number of shares of Common Stock into which a share of Class B Preferred Stock may be converted at such time.  Concurrently with the Special Dividend paid pursuant to this Section 9(D)(1), the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate of all shares of Class B Preferred Stock shall be adjusted by dividing the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate, respectively, in effect immediately before such Extraordinary Distribution or Pro Rata Repurchase by the Sec. 9(D) Non-Dilutive Share Fraction determined pursuant to this Section 9(D)(1).

(2)        The Corporation and the Board of Directors shall each use its best efforts to take all necessary steps or to take all actions as are reasonably necessary or appropriate for declaration of the Special Dividend provided in Section 9(D)(1) but shall not be required to call a special meeting of shareholders in order to implement the provisions thereof.  If for any reason the Board of Directors is precluded from giving full effect to the Special Dividend provided in Section 9(D)(1), then no such Special Dividend shall be declared, but instead the Conversion Price shall automatically be adjusted by dividing the Conversion Price in effect immediately before the event by the Sec. 9(D) Non-Dilutive Share Fraction, and the Liquidation Price and the Regular Preferred Dividend Rate will not be adjusted.  If subsequently the Board of Directors is able to give full effect to the Special Dividend as provided in Section 9(D)(1), then such Special Dividend will be declared and other adjustments will be made in accordance with the provisions of Section 9(D)(1) and the adjustment in the Conversion Price as provided in this Section 9(D)(2) will automatically be reversed and nullified prospectively.

(E)       Notwithstanding any other provision of this Section 9, the Corporation shall not be required to make (i) any Special Dividend or any adjustment of the Conversion Price, the Liquidation Price or the Regular Preferred Dividend Rate unless such adjustment would require an increase or decrease of at least one percent (1%) in the number of shares of Class B Preferred Stock outstanding, or, (ii) if no additional shares of Class B Preferred Stock are issued, any adjustment of the Conversion Price unless such adjustment would require an increase or decrease of at least one percent (1%) in the Conversion Price.  Any lesser adjustment

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shall be carried forward and shall be made no later than the time of, and together with, the next subsequent adjustment which, together with any adjustment or adjustments so carried forward, shall amount to an increase or decrease of at least one percent (1%) of the number of shares of Class B Preferred Stock outstanding or, if no additional shares of Class B Preferred Stock are being issued, an increase or decrease of at least one percent (1%) of the Conversion Price, whichever the case may be.

(F)       If the Corporation shall make any dividend or distribution on the Common Stock or issue any Common Stock, other capital stock or other security of the Corporation or any rights or warrants to purchase or acquire any such security, which transaction does not result in an adjustment to the number of shares of Class B Preferred Stock outstanding or the Conversion Price pursuant to the foregoing provisions of this Section 9, the Board of Directors of the Corporation may, in its sole discretion, consider whether such action is of such a nature that some type of equitable adjustment should be made in respect of such transaction.  If in such case the Board of Directors of the Corporation determines that some type of adjustment should be made, an adjustment shall be made effective as of such date as determined by the Board of Directors of the Corporation.  The determination of the Board of Directors of the Corporation as to whether some type of adjustment should be made pursuant to the foregoing provisions of this Section 9(F), and, if so, as to what adjustment should be made and when, shall be final and binding on the Corporation and all shareholders of the Corporation.  The Corporation shall be entitled to make such additional adjustments, in addition to those required by the foregoing provisions of this Section 9, as shall be necessary in order that any dividend or distribution in shares of capital stock of the Corporation, subdivision, reclassification or combination of shares of the Corporation or any recapitalization of the Corporation shall not be taxable to holders of the Common Stock.

(G)       For purposes hereof, the following definitions shall apply:

(1)        “Extraordinary Distribution” shall mean any dividend or other distribution to holders of Common Stock effected while any of the shares of Class B Preferred Stock are outstanding of (i) cash or (ii) any shares of capital stock of the Corporation (other than shares of Common Stock), other securities of the Corporation (other than securities of the type referred to in Section 9(B)), evidences of indebtedness of the Corporation or any other person or any other property (including shares of any subsidiary of the Corporation), or any combination thereof, where the aggregate amount of such cash dividend or other distribution together with the amount of all cash dividends and other distributions made during the preceding period of twelve (12) months, when combined with the aggregate amount of all Pro Rata Repurchases (for this purpose, including only that portion of the aggregate purchase price of such Pro Rata Repurchase which is in excess of the Fair Market Value of the Common Stock repurchased as determined on the applicable expiration date (including all extensions thereof) of any tender offer or exchange offer which is a Pro Rata Repurchase, or the date of purchase with respect to any other Pro Rata Repurchase which is not a tender offer or exchange offer) made during such period, exceeds twelve and one-half percent (12.5%) of the aggregate Fair Market Value of all shares of Common Stock outstanding on the day before the ex-dividend date with respect to such Extraordinary Distribution which is paid in cash and on the distribution date with respect to an Extraordinary Distribution which is paid other than in cash.  The Fair Market Value of an Extraordinary Distribution for purposes of Section 9(D) shall be the sum of the Fair Market Value of such Extraordinary Distribution plus the aggregate amount of any cash dividends or

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other distributions which are not Extraordinary Distributions made during such twelve month period and not previously included in the calculation of an adjustment pursuant to Section 9(D), but shall exclude the aggregate amount of regular quarterly dividends declared by the Board of Directors and paid by the Corporation in such twelve month period.

(2)        “Fair Market Value” shall mean, as to shares of Common Stock or any other class of capital stock or securities of the Corporation or any other issuer which are publicly traded, the average of the Current Market Prices (as hereinafter defined) of such shares or securities for each day of the Adjustment Period (as hereinafter defined).  “Current Market Price” of publicly traded shares of Common Stock or any other class of capital stock or other security of the Corporation or any other issuer for a day shall mean the last reported sales price, regular way, or, in case no sale takes place on such day, the average of the reported closing bid and asked prices, regular way, in either case as reported on the New York Stock Exchange Composite Tape or, if such security is not listed or admitted to trading on the New York Stock Exchange, on the principal national securities exchange on which such security is listed or admitted to trading or, if not listed or admitted to trading on any national securities exchange, on the NASDAQ National Market System or, if such security is not quoted on such National Market System, the average of the closing bid and asked prices on each such day in the over-the-counter market as reported by NASDAQ or, if bid and asked prices for such security on each such day shall not have been reported through NASDAQ, the average of the bid and asked prices for such day as furnished by any New York Stock Exchange member firm regularly making a market in such security selected for such purpose by the Board of Directors of the Corporation on each trading day during the Adjustment Period.  “Adjustment Period” shall mean the period of five consecutive trading days, selected by the Board of Directors of the Corporation, during the twenty (20) trading days preceding, and including, the date as of which the Fair Market Value of a security is to be determined.  The "Fair Market Value" of any security which is not publicly traded or of any other property shall mean the fair value thereof as determined by an independent investment banking or appraisal firm experienced in the valuation of such securities or property selected in good faith by the Board of Directors of the Corporation, or, if no such investment banking or appraisal firm is in the good faith judgment of the Board of Directors available to make such determination, as determined in good faith by the Board of Directors of the Corporation.

(3)        "Non-Dilutive Amount" in respect of an issuance, sale or exchange by the Corporation of any right or warrant to purchase or acquire shares of Common Stock (including any security convertible into or exchangeable for shares of Common Stock) shall mean the difference between (i) the product of the Fair Market Value of a share of Common Stock on the day preceding the first public announcement of such issuance, sale or exchange multiplied by the maximum number of shares of Common Stock which could be acquired on such date upon the exercise in full of such rights or warrants (including upon the conversion or exchange of all such convertible or exchangeable securities), whether or not exercisable (or convertible or exchangeable) at such date, and (ii) the aggregate amount payable pursuant to such right or warrant to purchase or acquire such maximum number of shares of Common Stock; provided, however, that in no event shall the Non-Dilutive Amount be less than zero.  For purposes of the foregoing sentence, in the case of a security convertible into or exchangeable for shares of Common Stock, the amount payable pursuant to a right or warrant to purchase or acquire shares of Common Stock shall be the Fair Market Value of such security on the date of the issuance, sale or exchange of such security by the Corporation.

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(4)        "Pro Rata Repurchase" shall mean any purchase of shares of Common Stock by the Corporation or any subsidiary thereof, whether for cash, shares of capital stock of the Corporation, other securities of the Corporation, evidences of indebtedness of the Corporation or any other person or any other property (including shares of a subsidiary of the Corporation ), or any combination thereof, effected while any of the shares of Class B Preferred Stock are outstanding, pursuant to any tender offer or exchange offer subject to Section 13(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or any successor provision of law, or pursuant to any other offer available to substantially all holders of Common Stock, provided, however, that no purchase of shares by the Corporation or any subsidiary thereof made in open market transactions shall be deemed a Pro Rata Repurchase.  For purposes of this Section 9(G), shares shall be deemed to have been purchased by the Corporation or any subsidiary thereof "in open market transactions" if they have been purchased substantially in accordance with the requirements of Rule 10b-18 as in effect under the Exchange Act on the date shares of Class B Preferred Stock are initially issued by the Corporation or on such other terms and conditions as the Board of Directors of the Corporation shall have determined are reasonably designed to prevent such purchases from having a material effect on the trading market for the Common Stock.

(H)       Whenever an adjustment increasing the number of shares of Class B Preferred Stock outstanding is required pursuant hereto, the Board of Directors shall take action as is necessary so that a sufficient number of shares of Class B Preferred Stock are designated with respect to such increase resulting from such adjustment.  Whenever an adjustment to the Conversion Price, the Liquidation Price or the Regular Preferred Dividend Rate of the Class B Preferred Stock is required pursuant hereto, the Corporation shall forthwith place on file with the transfer agent for the Common Stock and the Class B Preferred Stock, if there be one, and with the Treasurer of the Corporation, a statement signed by the Treasurer or any Assistant Treasurer of the Corporation stating the adjusted Conversion Price, Liquidation Price and Regular Preferred Dividend Rate determined as provided herein.  Such statement shall set forth in reasonable detail such facts as shall be necessary to show the reason and the manner of computing such adjustment, including any determination of Fair Market Value involved in such computation.  Promptly after each adjustment to the number of shares of Class B Preferred Stock outstanding, the Conversion Price, the Liquidation Price or the Regular Preferred Dividend Rate, the Corporation shall mail a notice thereof and of the then prevailing number of shares of Class B Preferred Stock outstanding, the Conversion Price, the Liquidation Price and the Regular Preferred Dividend Rate to each holder of shares of Class B Preferred Stock.

10.       Miscellaneous.

            (A)       All notices referred to herein shall be in writing, and all notices hereunder shall be deemed to have been given upon the earlier of receipt thereof or three (3) business days after the mailing thereof if sent by registered mail (unless first-class mail shall be specifically permitted for such notice under the terms hereof) with postage prepaid, addressed:  (i) if to the Corporation, to its office at 5959 Las Colinas Boulevard, Irving, Texas 75039 (Attention:  Treasurer) or to the transfer agent for the Class B Preferred Stock, or other agent of the Corporation designated as permitted hereby or (ii) if to any holder of the Class B Preferred Stock or Common Stock, as the case may be, to such holder at the address of such holder as listed in the stock record books of the Corporation (which may include the records of any transfer agent for the Class B Preferred Stock or Common Stock, as the case may be) or (iii) to such other address as the Corporation or any such holder, as the case may be, shall have designated by notice similarly given.

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            (B)       The term "Common Stock" as used herein means the Corporation’s no par value common stock, as the same exists at the Effective Date, or any other class of stock resulting from successive changes or reclassifications of such Common Stock consisting solely of changes in par value, or from par value to without par value, or from without par value to par value.  In the event that, at any time as a result of an adjustment made pursuant to Section 9 hereof, the holder of any shares of the Class B Preferred Stock upon thereafter surrendering such shares for conversion shall become entitled to receive any shares or other securities of the Corporation other than shares of Common Stock, the anti-dilution provisions contained in Section 9 hereof shall apply in a manner and on terms as nearly equivalent as practicable to the provisions with respect to Common Stock, and the provisions of Sections 1 through 8 and 10 hereof with respect to the Common Stock shall apply on like or similar terms to any such other shares of securities.

            (C)       The term “Effective Date” shall mean the date of effectiveness of the Certificate of Merger of Lion Acquisition Subsidiary Corporation with and into Mobil Corporation filed in the office of the Secretary of State of the State of Delaware.

            (D)       The Corporation shall pay any and all stock transfer and documentary stamp taxes that may be payable in respect of any issuance or delivery of shares of Class B Preferred Stock or shares of Common Stock or other securities issued on account of Class B Preferred Stock pursuant thereto or certificate representing such shares or securities.  The Corporation shall not, however, be required to pay any such tax which may be payable in respect of any transfer involved in the issuance or delivery of shares of Class B Preferred Stock or Common Stock or other securities in a name other than that in which the shares of Class B Preferred Stock with respect to which such shares or other securities are issued or delivered were registered, or in respect of any payment to any person with respect to any such shares or securities other than a payment to the registered holder thereof, and shall not be required to make any such issuance, delivery or payment unless and until the person otherwise entitled to such issuance, delivery or payment has paid to the Corporation the amount of any such tax or has established, to the satisfaction of the Corporation, that such tax has been paid or is not payable.

            (E)       In the event that a holder of shares of Class B Preferred Stock shall not by written notice designate the name in which shares of Common Stock to be issued upon conversion of such shares should be registered or to whom payment upon redemption of shares of Class B Preferred Stock should be made or the address to which the certificate or certificates representing such shares, or such payment, should be sent, the Corporation shall be entitled to register such shares, and make such payment, in the name of the holder of such Class B Preferred Stock as shown on the records of the Corporation and to send the certificate or certificates or other documentation representing such shares, or such payment, to the address of such holder shown on the records of the Corporation.

            (F)       The Corporation may appoint, and from time to time discharge and change, a transfer agent for the Class B Preferred Stock.  Upon any such appointment or discharge of a transfer agent, the Corporation shall send notice thereof by first-class mail, postage prepaid, to each holder of record of Class B Preferred Stock.

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            (G)       Any shares of Common Stock into which the shares of Class B Preferred Stock shall be converted, may be uncertificated shares, provided  that the names of the holders of all uncertificated shares and the number of such shares held by each holder shall be registered at the offices of the Corporation or the transfer agent for such shares.  In the event that any shares shall be uncertificated, all references herein to surrender or issuance of stock certificates shall have no application to such uncertificated shares.

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EX-3.(II)

 

EXHIBIT 3(ii)

EXXON MOBIL CORPORATION

INCORPORATED IN NEW JERSEY

BY-LAWS

ARTICLE I

Meetings of Shareholders

1.   Meetings of shareholders may be held on such date and at such time and place, within or without the State of New Jersey, as may be fixed by the board of directors and stated in the notice of meeting.

2.   The date for each annual meeting of shareholders, fixed as provided in Section 1 of this Article I, shall be a date not more than thirteen months after the date on which the last annual meeting of shareholders was held. The directors shall be elected at the annual meeting of shareholders.

3.   Special meetings of the shareholders may be called by the board of directors, the chairman of the board or the president.

4.   Except as otherwise provided by statute, written notice of the date, time, place and purpose or purposes of every meeting of shareholders shall be given not less than ten nor more than sixty days before the date of the meeting, either personally or by mail, to each shareholder of record entitled to vote at the meeting.  The business transacted at meetings shall be confined to the purposes specified in the notice.

5.   Unless otherwise provided by statute the holders of shares entitled to cast a majority of votes at a meeting, present either in person or by proxy, shall constitute a quorum at such meeting.  Less than a quorum may adjourn.

6.   For the purpose of determining the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or for the purpose of determining shareholders entitled to receive payment of any dividend or allotment of any right, or for the purpose of any other action, the board of directors may fix in advance a date as the record date for any such determination of shareholders.  Such date shall not be more than sixty nor less than ten days before the date of such meeting, nor more than sixty days prior to any other action.

7.   The board of directors may, in advance of any shareholders' meeting, appoint one or more inspectors to act at the meeting or any adjournment thereof.  If inspectors are not so appointed by the board or shall fail to qualify, the person presiding at a shareholders' meeting may, and at the request of any shareholder entitled to vote thereat, shall, make such appointment.  In case any person appointed as inspector fails to appear or act, the vacancy may be filled by appointment made by the board in advance of the meeting or at the meeting by the person presiding at the meeting. Each inspector, before entering upon the discharge of the duties of inspector, shall take and sign an oath faithfully to execute such duties at such meeting with strict impartiality and according to the best of the inspector's ability.

     The inspectors shall determine the number of shares outstanding and the voting power of each, the shares represented at the meeting, the existence of a quorum, the validity and effect of proxies, and shall receive votes or consents, hear and determine all challenges and questions arising in connection with the right to vote, count and tabulate all votes or consents, determine the result, and do such acts as are proper to

conduct the election or vote with fairness to all shareholders.  If there are three or more inspectors, the act of a majority shall govern.  On request of the person presiding at the meeting or any shareholder entitled to vote thereat, the inspectors shall make a report in writing of any challenge, question or matter determined by them.  Any report made by them shall be prima facie evidence of the facts therein stated, and such report shall be filed with the minutes of the meeting.

ARTICLE II

Board of Directors

1.   The business and affairs of the corporation shall be managed by its board of directors consisting of not less than ten nor more than nineteen members, who shall hold office until the next annual meeting and until their successors shall have been elected and qualified.  The actual number of directors shall be determined from time to time by resolution of the board.  If at any time, except at the annual meeting, the number of directors shall be increased, the additional director or directors may be elected by the board, to hold office until the next annual meeting and until their successors shall have been elected and qualified.

2.   The organization meeting of the board of directors, for the purpose of organization or otherwise, shall be held without further notice on the day of the annual meeting of shareholders, at such time and place as shall be fixed from time to time pursuant to resolution of the board.  Other regular meetings of the board may be held without further notice at such times and places as shall be fixed from time to time pursuant to resolution of the board.  The chairman of the board, the president, any vice president who is a member of the board, or the secretary may change the day or hour or place of any single regular meeting from that determined by the board upon causing that prior notice of such change be transmitted to all directors.

     Special meetings of the board may be called at the direction of the chairman of the board, of the president or of any vice president who is a member of the board, or, in the absence of such officers, at the direction of any one of the directors.  Any such meeting shall be held on such date and at such time and place as may be designated in the notice of the meeting.

     Notices required under this section may be transmitted in person, in writing, or by telephone, telegram, cable or radio, and shall be effective whether or not actually received, provided they are duly transmitted not less than forty-eight hours in advance of the meeting.  Notice may be waived in writing before or after a meeting.  No notice or waiver need specify the business scheduled for any board meeting and any business may be transacted at either a regular or special meeting.

3.   Five directors shall constitute a quorum for the transaction of business, except that any directorship not filled at the annual meeting and any vacancy, however caused, occurring in the board may be filled by the affirmative vote of a majority of the remaining directors even though less than a quorum of the board, or by a sole remaining director.  At any meeting of the board, whether or not a quorum is present, a majority of those present may adjourn the meeting.  Notice of an adjourned meeting need not be given if the time and place are fixed at the meeting adjourning and if the period of adjournment does not exceed ten days in any one adjournment.

4.   (a) The provisions of this Section 4 of Article II shall be operative during any emergency in the conduct of the business of the corporation resulting from an attack on the United States or any nuclear or atomic disaster or from the imminent threat of such an attack or disaster.  For the purpose of this Section 4 of Article II, such an emergency is defined

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as any period following (i) an enemy attack on the continental United States or any nuclear or atomic disaster as a result and during the period of which the means of communication or travel within the continental United States are disrupted or made uncertain or unsafe, or (ii) a determination as herein provided that such an attack or disaster is imminent or has occurred.  The commencement and termination of the period of any such emergency may be determined by the chairman of the board or, in the event of the death, absence or disability of the chairman of the board, by the president, or in the event of the death, absence or disability of both the chairman of the board and the president, by such person or persons as the board of directors may from time to time designate, but in the absence of such specific designation, by the executive or senior vice president who has been designated pursuant to the authority of Section 6 of Article IV of these by-laws to exercise the powers and perform the duties of the chairman of the board and the president.  To the extent not inconsistent with the provisions of this Section 4 of Article II, the by-laws in their entirety shall remain in effect during any such emergency.

     (b) Before or during any such emergency, the board may change the head office or designate several alternative head offices or regional offices, or authorize the officers to do so, said change to be effective during the emergency.

     (c) The officers or other persons designated by title in a list approved by the board before or during the emergency, all who are known to be alive and available to act in such order of priority and subject to such conditions and for such period of time, not longer than reasonably necessary after the termination of the emergency, as may be provided in the resolution of the board approving the list, shall, to the extent required to provide a quorum at any meeting of the board, be deemed and shall have all the powers of directors for such meeting.  Unless so designated, an officer who is not a director shall not be deemed a director for the foregoing purpose.

     (d) Meetings of the board may be called by any officer or director or in the absence of all officers and directors by any person designated in a list approved by the board pursuant to subsection (c) of this Section 4. Any such meeting shall be held on such date and at such time and place as may be designated in the notice of the meeting.  Notice of any such meeting need be given only to such of the directors as it may be feasible to reach at the time and such of the persons designated in such list as is considered advisable in the judgment of the person calling the meeting.  Any such notice may be transmitted in person, in writing, or by telephone, telegram, cable or radio, or by such other means as may be feasible at the time, shall be effective whether or not actually received and shall be given at such time in advance of the meeting as, in the judgment of the person calling the meeting, circumstances permit.

     (e) Three directors shall constitute a quorum for the transaction of business.

     (f) Before or during any such emergency, the board by resolution may (i) appoint one or more committees in addition to or in substitution for one or more of those appointed pursuant to the provisions of Article III of these by-laws to act during such emergency and (ii) take any of the actions listed in Section 2 of Article III of these by-laws in regard to any committee established pursuant to (i) of this subsection (f).  Each such committee shall have at least three members, none of whom need be a director.  To the extent provided in such resolution, each such committee shall have and may exercise all the authority of the board, except that no such committee shall take the action which Section 1 of Article III of these by-laws prohibits committees of the board to take.

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(g) Before or during any such emergency, the board may provide and from time to time modify, lines of succession in the event that during such an emergency any or all officers or agents of the corporation or any or all members of any committee of the board shall for any reason be rendered incapable of discharging their duties.

     (h) No officer, director or employee acting in accordance with this Section 4 of Article II shall be liable except for willful misconduct.  No officer, director or employee shall be liable for any action taken in good faith in such an emergency in furtherance of the ordinary business affairs of the corporation even though not authorized by the by-laws then in effect.

     (i) Persons may conclusively rely upon a determination made pursuant to subsection (a) of this Section 4 that an emergency as therein defined exists regardless of the correctness of such determination.

5.   No contract or other transaction between the corporation and one or more of its directors or between the corporation and any other corporation, firm or association of any type or kind in which one or more of its directors are directors or are otherwise interested, shall be void or voidable solely by reason of such common directorship or interest, or solely because such director or directors are present at the meeting of the board or a committee thereof which authorizes or approves the contract or transaction, or solely because such director's or directors' votes are counted for such purpose, if (a) the contract or other transaction is fair and reasonable as to this corporation at the time it is authorized, approved or ratified, or (b) the fact of the common directorship or interest is disclosed or known to the board or committee and the board or committee authorizes, approves or ratifies the contract or transaction by unanimous written consent, provided at least one director so consenting is disinterested, or by affirmative vote of a majority of the disinterested directors, even though the disinterested directors be less than a quorum, or (c) the fact of the common directorship or interest is disclosed or known to the shareholders and they authorize, approve or ratify the contract or transaction.

ARTICLE III

Committees of the Board

1.   The board, by resolution adopted by a majority of the entire board, may appoint from among its members an executive committee and one or more other committees, each of which shall have at least three members.  To the extent provided in such resolution, each such committee shall have and may exercise all the authority of the board, except that no such committee shall (a) make, alter or repeal any by-law of the corporation; (b) elect any director, or remove any officer or director; (c) submit to shareholders any action that requires shareholders' approval; or (d) amend or repeal any resolution theretofore adopted by the board which by its terms is amendable or repealable only by the board.

2.   The board, by resolution adopted by a majority of the entire board, may (a) fill any vacancy in any such committee; (b) appoint one or more directors to serve as alternate members of any such committee, to act in the absence or disability of members of any such committee with all the powers of such absent or disabled members; (c) abolish any such committee at its pleasure; (d) remove any director from membership on such committee at any time, with or without cause; and (e) establish as a quorum for any such committee less than a majority of the entire committee, but in no case less than the greater of two persons or one-third of the entire committee.

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3.   Actions taken at a meeting of any such committee shall be reported to the board at its next meeting following such committee meeting; except that, when the meeting of the board is held within two days after the committee meeting, such report shall, if not made at the first meeting, be made to the board at its second meeting following such committee meeting.

ARTICLE IV

Officers

1.   The board of directors at the organization meeting on the day of the annual election of directors shall elect a chairman of the board, a president, one or more vice presidents as the board may determine, any one or more of whom may be designated as executive vice president or as senior vice president or in such special or limiting style as the board may determine, a secretary, a treasurer, a controller, a general counsel, and a general tax counsel.  The chairman of the board and the president shall each be a director, but the other officers need not be members of the board.

2.   The board of directors may from time to time elect, or authorize an officer of the corporation to appoint in writing, assistant secretaries, assistant treasurers, assistant controllers, and such other officers as the board may designate.

3.   All officers of the corporation, as between themselves and the corporation, shall have such authority and perform such duties in the management of the corporation as may be provided in these by-laws, or as may be determined by resolution of the board not inconsistent with these by-laws.

4.   The chairman of the board shall be chief executive officer of the corporation and shall preside at all meetings of shareholders and directors.  Subject to the board of directors, the chairman of the board shall have general care and supervision of the business and affairs of the corporation.  In the absence of the president, the chairman of the board shall exercise the powers and perform the duties of the president.

5.   The president shall, subject to the board of directors, direct the current administration of the business and affairs of the corporation.  In the absence of the chairman of the board, the president shall preside at meetings of the shareholders and directors and exercise the other powers and duties of the chairman.

6.   In the event of the death, absence, or disability of the chairman of the board and the president, an executive or senior vice president may be designated by the board to exercise the powers and perform the duties of those offices.

7.   The secretary shall give notice of all meetings of the shareholders and of the board of directors.  The secretary shall keep records of the votes at elections and of all other proceedings of the shareholders and of the board.  The secretary shall have all the authority and perform all the duties normally incident to the office of secretary and shall perform such additional duties as may be assigned to the secretary by the board, the chairman of the board or the president.

     The assistant secretaries shall perform such of the duties of the secretary as may be delegated to them by the secretary.

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8.   The treasurer shall, unless the board of directors specifies otherwise, be the principal financial officer of the corporation.  The treasurer shall have charge and custody of all funds and securities of the corporation; receive and give receipts for monies paid to the corporation, and deposit such monies in the corporation's name in such banks or other depositories as shall be selected for the purpose; and shall cause money to be paid out as the corporation may require.  The treasurer shall have all the authority and perform all the duties normally incident to the office of treasurer and shall perform such additional duties as may be assigned to the treasurer by the board of directors, the chairman of the board or the president.

     The assistant treasurers shall perform such of the duties of the treasurer as may be delegated to them by the treasurer.

9.   The controller shall be the principal accounting and financial control officer of the corporation.  The controller shall be responsible for the system of financial control of the corporation, including internal audits, the maintenance of its accounting records, and the preparation of the corporation's financial statements.  The controller shall periodically inform the board of directors of the corporation's financial results and position.  The controller shall have all the authority and perform all the duties normally incident to the office of controller and shall perform such additional duties as may be assigned to the controller by the board of directors, the chairman of the board or the president.

     The assistant controllers shall perform such of the duties of the controller as may be delegated to them by the controller.

10.  The general counsel shall advise the board of directors and officers on legal matters, except those relating to taxes.  The general tax counsel shall advise the board of directors and officers on legal matters relating to taxes.  Each shall perform such additional duties as may be assigned to either of them by the board of directors, the chairman of the board or the president.

11.  Any vacancy occurring among the officers, however caused, may be filled by the board of directors except that any vacancy in the office of an assistant secretary, assistant treasurer or assistant controller appointed by an officer of the corporation may be filled by the officer, if any, then authorized by the board to make appointments to such office.

12.  Any officer may be removed by the board with or without cause, and any assistant secretary, assistant treasurer or assistant controller appointed by an officer of the corporation may be removed with or without cause by the officer, if any, then authorized by the board to make appointments to such office.

ARTICLE V

Divisions and Division Officers

1.   The board of directors may from time to time establish one or more divisions of the corporation and assign to such divisions responsibilities for such of the corporation's business, operations and affairs as the board may designate.

2.   The board of directors may appoint or authorize an officer of the corporation to appoint in writing officers of a division.  Unless elected or appointed an officer of the corporation by the board of directors or pursuant to authority granted by the board, an officer of a division shall not as such be an officer of the corporation, except that such person shall be an officer of the corporation for the purposes of executing and

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delivering documents on behalf of the corporation or for other specific purposes, if and to the extent that such person may be authorized to do so by the board of directors.  Unless otherwise provided in the writing appointing an officer of a division, such person's term of office shall be for one year and until that person's successor is appointed and qualified. Any officer of a division may be removed with or without cause by the board of directors or by the officer, if any, of the corporation then authorized by the board of directors to appoint such officer of a division.

3.   The board of directors may prescribe or authorize an officer of the corporation or an officer of a division to prescribe in writing the duties and powers and authority of officers of divisions.

ARTICLE VI

Transfer of Shares

1.   Shares of the corporation shall be transferable on the records of the corporation in accordance with the provisions of Chapter 8 of the Uniform Commercial Code (New Jersey Statutes 12A:8-101 et seq.), as amended from time to time, except as otherwise provided in the New Jersey Business Corporation Act (New Jersey Statutes 14A:l-l et seq.).

2.   In the case of lost, destroyed or wrongfully taken certificates, transfer shall be made only after the receipt of a sufficient indemnity bond, if required by the board of directors, and satisfaction of other reasonable requirements imposed by the board.

3.   The board of directors may from time to time appoint one or more transfer agents and one or more registrars of transfers.  All share certificates shall bear the signature, which may be a facsimile, of a transfer agent and of a registrar.  The functions of transfer agents and registrars shall conform to such regulations as the board may from time to time prescribe.  The board may at any time terminate the appointment of any transfer agent or registrar.

ARTICLE VII

Fiscal Year

     The fiscal year of the corporation shall be the calendar year.

ARTICLE VIII

Corporate Seal

1.   The corporate seal is, and until otherwise ordered by the board of directors shall be, a circle containing the words "EXXON MOBIL CORPORATION, CORPORATE SEAL, 1882, NEW JERSEY" and may be an impression thereof or printed or other facsimile reproduction.

2.   The impression of the seal may be made and attested by either the secretary or an assistant secretary for the authentication of contracts and other papers requiring the seal.

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ARTICLE IX

Amendments

     The board of directors shall have the power to make, alter and repeal the by-laws of the corporation, but by-laws made by the board may be altered or repealed, and new by-laws made, by the shareholders.

ARTICLE X

Indemnification

1.   The corporation shall indemnify to the full extent from time to time permitted by law any director or former director or officer or former officer made, or threatened to be made, a party to, or a witness or other participant in, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative, arbitrative, legislative, investigative, or of any other kind, by reason of the fact that such person is or was a director, officer, employee or other corporate agent of the corporation or any subsidiary of the corporation or serves or served any other enterprise at the request of the corporation (including service as a fiduciary with respect to any employee benefit plan of the corporation or any subsidiary of the corporation) against expenses (including attorneys' fees), judgments, fines, penalties, excise taxes and amounts paid in settlement, actually and reasonably incurred by such person in connection with such action, suit or proceeding, or any appeal therein.  No indemnification pursuant to this Article X shall be required with respect to any settlement or other nonadjudicated disposition of any threatened or pending action or proceeding unless the corporation has given its prior consent to such settlement or other disposition.

2.   As any of the foregoing expenses are incurred, they shall be paid by the corporation for the director or former director or officer or former officer in advance of the final disposition of the action, suit or proceeding promptly upon receipt of an undertaking by or on behalf of such person to repay such payments if it shall ultimately be determined that such person is not entitled to be indemnified by the corporation.

3.   The foregoing indemnification and advancement of expenses shall not be deemed exclusive of any other rights to which any person indemnified may be entitled.

4.   The rights provided to any person by this Article X shall be enforceable against the corporation by such person, who shall be presumed to have relied upon it in serving or continuing to serve as a director or in any of the other capacities set forth in this Article X.  No elimination of or amendment to this Article X shall deprive any person of rights hereunder arising out of alleged or actual occurrences, acts or failures to act occurring prior to notice to such person of such elimination or amendment.  The rights provided to any person by this Article X shall inure to the benefit of such person's legal representative.

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EX-10.(III) (A3)

 

EXHIBIT 10(iii)(a.3)

November 24, 2015

Exxon Mobil Corporation

Extended Provisions for Restricted Stock Unit Agreements - Settlement in Shares

1.Effective Date and Credit of Restricted Stock Units.  If Grantee accepts the award on or before March 7, 2016, this Agreement will become effective the date the Corporation receives the award acceptance. After this agreement becomes effective, the Corporation will credit to Grantee the number of restricted stock units specified in the award package. Subject to the terms and conditions of this Agreement, each restricted stock unit ("unit") will entitle Grantee to receive in settlement of the unit one share of the Corporation's common stock.

2.Conditions.  If credited, the units will be subject to the provisions of this Agreement, and to such regulations and requirements as the administrative authority of the Program may establish from time to time. The units will be credited to Grantee only on the condition that Grantee accepts such provisions, regulations, and requirements.

3.Restrictions and Riskof Forfeiture.  During the applicable restricted periods specified in section 4 of this Agreement,

a)the units under restriction may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and any attempt to do so will be null and void; and

b)the units under restriction may be forfeited as provided in section 6.

4.Restricted Periods.  The restricted periods will commence when the units are credited to Grantee and, unless the units have been forfeited earlier under section 6, will expire as follows, whether or not Grantee is still an employee:

a)with respect to 50% of the units, on November 24, 2020; and

b)with respect to the remaining units, on the later to occur of

(i)November 24,  2025, or

(ii)the first day of the calendar year immediately following the year in which Grantee terminates; except that

c)the restricted periods will automatically expire with respect to all shares on the death of Grantee.

5.No Obligation to Credit Units.  The Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if Grantee fails to accept the award on or before March 7, 2016. In addition, whether or not Grantee has accepted the award, the Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if, before the units are credited:

a)Grantee terminates (other than by death) before standard retirement time within the meaning of the Program, except to the extent the administrative authority of the Program determines Grantee may receive units under this Agreement; or

b)Grantee is determined to have engaged in detrimental activity within the meaning of the Program.

6.Forfeiture of Units After Crediting.  Until the applicable restricted period specified in section 4 has expired, the units under restriction will be forfeited or subject to forfeiture in the following circumstances:

Termination

If Grantee terminates (other than by death) before standard retirement time within the meaning of the Program, all units for which the applicable restricted periods have not expired will be automatically forfeited as of the date of termination, except to the extent the administrative authority determines Grantee may retain units issued under this Agreement.

Detrimentalactivity 

If Grantee is determined to have engaged in detrimental activity within the meaning of the Program, either before or after termination, all units for which the applicable restricted periods have not expired will be automatically forfeited as of the date of such determination.

1

Attemptedtransfer 

The units are subject to forfeiture in the discretion of the administrative authority if Grantee attempts to sell, assign, transfer, pledge, or otherwise dispose of or encumber them during the applicable restricted periods.

Applicablelaw 

The units are subject to forfeiture in whole or in part as the administrative authority deems necessary to comply with applicable law or Corporation policy including, without limitation, any clawback obligations determined to be owed by Grantee to the Corporation in connection with this or other awards.

7.Taxes.  Notwithstanding the restrictions on transfer that otherwise apply, the Corporation in its sole discretion may withhold units, or shares otherwise deliverable in settlement of units, either at the time of crediting, at the time of settlement, or at any other time in order to satisfy any required withholding, social security, and similar taxes or contributions (collectively, "required taxes"). Withheld units or shares may be retained by the Corporation or sold on behalf of Grantee. The Corporation in its sole discretion may also withhold any required taxes from dividend equivalents paid on the units.

8.Form of Units; No Shareholder Status.  The units will be represented by book-entry credits in records maintained by or on behalf of the Corporation. Units will be unfunded and unsecured promises by the Corporation to deliver shares in the future upon the terms and subject to the conditions of this Agreement. Grantee will not be a shareholder of the Corporation with respect to units prior to the time shares are actually registered in Grantee's name in settlement of such units in accordance with section 9.

9.Settlement of Units.  If and when the applicable restricted period expires with respect to any units, subject to section 7, the Corporation will issue shares, free of restriction and registered in the name of Grantee, in settlement of such units. Such shares will be delivered promptly after such expiration to or for the account of Grantee either in certificated form or by book-entry transfer in accordance with the procedures of the administrative authority in effect at the time.

10.Dividend Equivalents.  The Corporation will pay to Grantee cash with respect to each credited unit corresponding in amount, currency, and timing to cash dividends that would be payable with respect to a share of common stock outstanding on each record date that occurs during the applicable restricted period. Alternatively, the administrative authority may determine to reinvest such dividend equivalents in additional units which will be held subject to all the terms and conditions otherwise applicable to units under this Agreement.

11.Change in Capitalization.  If during the applicable restricted periods a stock split, stock dividend, or other relevant change in capitalization of the Corporation occurs, the administrative authority will make such adjustments in the number of units credited to Grantee, or in the number and type of securities deliverable to Grantee in settlement of such units and used in determining dividend equivalent amounts, as the administrative authority may determine to be appropriate. Any resulting new units or securities credited with respect to previously credited units that are still restricted under this Agreement will be delivered to and held by or on behalf of the Corporation and will be subject to the same provisions, restrictions, and requirements as those previously credited units.

12.Limits on the Corporation’s Obligations.  Notwithstanding anything else contained in this Agreement, under no circumstances will the Corporation be required to credit any units or issue or deliver any shares in settlement of units if doing so would violate any law or listing requirement that the administrative authority determines to be applicable.

13.Receipt orAccess to Program .  Grantee acknowledges receipt of or access to the full text of the Program.

14.Addresses for Communications.  To facilitate communications regarding this Agreement, Grantee agrees to notify the Corporation promptly of changes in current mailing and email addresses. Communications to the Corporation in connection with this Agreement should be directed to the Incentive Processing Office, or to such other address as the Corporation may designate by further notice to Grantee.

2

15.Transfer of Personal Data.  The administration of the Program and this Agreement, including any subsequent ownership of shares, involve the collection, use, and transfer of personal data about Grantee between and among the Corporation, selected subsidiaries and other affiliates of the Corporation, and third-party service providers such as Morgan Stanley and Computershare (the Corporation's transfer agent), as well as various regulatory and tax authorities around the world. This data includes Grantee's name, age, date of birth, contact information, work location, employment status, tax status, social security number, salary, nationality, job title, share ownership, and details of incentive awards granted, cancelled, vested or unvested, and related information. By accepting this award, Grantee authorizes such collection, use, and transfer of this data. Grantee may, at any time and without charge, view such data and require necessary corrections to it. Such data will at all times be held in accordance with applicable laws, regulations, and agreements.

16.No Employment Contract or Entitlement to Other or Future Awards.  This Agreement, the Corporation's incentive programs, and Grantee's selection for incentive awards do not imply or form a part of any contract or assurance of employment, and they do not in any way limit or restrict the ability of Grantee's employer to terminate Grantee's employment. Grantee acknowledges that the Corporation maintains and administers its incentive programs entirely in its discretion and that Grantee is not entitled to any other or future incentive awards of any kind in addition to those that have already been granted.

17.Governing Law and Consent to Jurisdiction .  This Agreement and the Program are governed by the laws of the State of New York without regard to any conflict of law rules. Any dispute arising out of or relating to this Agreement or the Program may be resolved in any state or federal court located within Dallas County, Texas, U.S.A. Grantee accepts that venue and submits to the personal jurisdiction of any such court. Similarly, the Corporation accepts such venue and submits to such jurisdiction.

18.Entire Agreement.  This Agreement constitutes the entire understanding between Grantee and the Corporation with respect to the subject matter of this Agreement.

3

EX-10.(III) (B2)

 

EXHIBIT 10(iii)(b.2)

EXXON MOBIL CORPORATION

EARNINGS BONUS UNIT AWARD

			Maximum	Maximum
			Settlement	Settlement
EBU		Number	Value Per	Value of
Number	Name of Grantee	of EBUs	EBU	Award
			$6.50

This EARNINGS BONUS UNIT AWARD is granted in Dallas County, Texas by Exxon Mobil Corporation (the "Corporation") effective November 24, 2015 (the "date of grant"), pursuant to the Short Term Incentive Program adopted by the Board of Directors of the Corporation on October 27, 1993, as amended (the "Program"). This award is subject to the provisions of this instrument and the Program and to such regulations and requirements as may be stipulated from time to time by the administrative authority defined in the Program and is granted on the condition that Grantee accepts such provisions, regulations, and requirements. This instrument incorporates by reference the provisions of the Program, as it may be amended from time to time, including without limitation the definitions of terms used in this instrument and defined in the Program.

1. Award. The Corporation has granted to Grantee the number of earnings bonus units ("EBUs") set forth above, with each EBU having the maximum settlement value set forth above. Subject to the other terms of this award, Grantee has the right, for each of these EBUs, to receive from the Corporation, promptly after the settlement date defined below, an amount of cash equal to the Corporation's cumulative earnings per common share (assuming dilution) as reflected in its quarterly earnings statements as initially filed in its quarterly or annual reports with the U.S. Securities and Exchange Commission commencing with earnings for the first full quarter following the date of grant to and including the last full quarter preceding the settlement date; provided, however, that the amount of such settlement will not exceed the maximum settlement value specified above.

2. Settlement Date. The settlement date of these EBUs will be the earlier of (i) the date of publication of the Corporation's quarterly earnings statement for the twelfth (12th) full quarter following the date of grant, or (ii) the date of publication of the Corporation's quarterly earnings statement which brings the cumulative earnings per common share (assuming dilution) as initially filed in its quarterly or annual reports with the U.S. Securities and Exchange Commission commencing with the first full quarter following the date of grant to an amount at least equal to the maximum settlement value per EBU specified above.

3. Annulment. This award is provisional until the Corporation actually pays cash in settlement of the award.

(a) If, before the Corporation pays such cash, Grantee terminates (other than by death) before standard retirement time within the meaning of the Program, this award will automatically expire as of the date of termination, except to the extent the administrative authority determines Grantee may retain this award.

(b) If, before the Corporation pays such cash, Grantee is determined to have engaged in detrimental activity within the meaning of the Program, this award will automatically expire as of the date of such determination.

(c) Provisional awards held by executive officers may also be subject to cancellation to comply with applicable law or Corporation policy including, without limitation, any clawback obligations determined to be owed by Grantee to the Corporation in connection with this or other awards.

4. Adjustments. The number of EBUs covered by this award and the meaning of the term "common share" will be adjusted by the administrative authority as it deems appropriate to give effect to any stock split, stock dividend or other relevant change in capitalization of the Corporation after the date of grant and prior to the settlement date.

5. Governing Law and Consent to Jurisdiction. This award and the Program are governed by the laws of the State of New York without regard to any conflict of law rules. Any dispute arising out of or relating to this award or the Program may be resolved in any state or federal court located within Dallas County, Texas, U.S.A. This award is issued on the condition that Grantee accepts such venue and submits to the personal jurisdiction of any such court. Similarly, the Corporation accepts such venue and submits to such jurisdiction.

EXXON MOBIL CORPORATION

EX-10.(III) (F4)

 

EXHIBIT 10(iii).(f.4)

Resolutions of the Board of Directors

Regarding Cash Compensation of Non-employee Directors

October 26, 2011

RESOLVED, that, effective January 1, 2012, each member of the Board of Directors who is not an employee of the Corporation or of any of its affiliated companies (a “non-employee director”) be compensated at the rate of $110,000 per annum, and that in addition,

(a) each non-employee director designated as Chair of the Audit Committee, Chair of the Compensation Committee, or as Presiding Director be compensated at the rate of $10,000 per annum; and

(c) non-employee directors receive no additional fees for serving on, or attending regular or special meetings of, the Board or any committee of the Board, or for execution of written consents to action in lieu of meetings of the Board or any such committee, but be reimbursed for reasonable expenses if any; and that the resolutions regarding non-employee director remuneration adopted by the Board of Directors on October 28, 2009 be, and hereby are, revoked.

EX-12

 

EXHIBIT 12

EXXON MOBIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		Years Ended December 31,
		2015	2014	2013	2012	2011
		(millions of dollars)
Income from continuing operations attributable to ExxonMobil		16,150	32,520	32,580	44,880	41,060
Excess/(shortfall) of dividends over earnings of affiliates
	accounted for by the equity method	(691)	(358)	3	(1,157)	(273)
Provision for income taxes		5,415	18,015	24,263	31,045	31,051
Capitalized interest		(7)	121	148	(67)	(159)
Noncontrolling interests in earnings of consolidated subsidiaries		401	1,095	868	2,801	1,146
		21,268	51,393	57,862	77,502	72,825
Fixed Charges:
	Interest expense - borrowings	211	157	137	117	77
	Capitalized interest	482	344	309	506	593
	Rental cost representative of interest factor	585	618	612	640	721
		1,278	1,119	1,058	1,263	1,391
Total adjusted earnings available for payment of fixed charges		22,546	52,512	58,920	78,765	74,216
Number of times fixed charges are earned		17.6	46.9	55.7	62.4	53.4

EX-21

 

EXHIBIT 21

Subsidiaries of the Registrant (1), (2) and (3) – at December 31, 2015

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Aera Energy LLC (5)	48.2	California
AKG Marketing Company Limited	87.5	Bahamas
Al-Jubail Petrochemical Company (4) (5)	50	Saudi Arabia
Ampolex (CEPU) Pte Ltd	100	Singapore
Ancon Insurance Company, Inc.	100	Vermont
Barnett Gathering, LLC	100	Texas
Barzan Gas Company Limited (5)	7	Qatar
BEB Erdgas und Erdoel GmbH & Co. KG (4) (5)	50	Germany
Cameroon Oil Transportation Company S.A. (5)	41.06	Cameroon
Canada Imperial Oil Limited	69.6	Canada
Caspian Pipeline Consortium (5)	7.5	Russia/Kazakhstan
Cross Timbers Energy, LLC (4) (5)	50	Delaware
Ellora Energy Inc.	100	Delaware
Esso Australia Resources Pty Ltd	100	Australia
Esso Deutschland GmbH	100	Germany
Esso Erdgas Beteiligungsgesellschaft mbH	100	Germany
Esso Exploration and Production Angola (Overseas) Limited	100	Bahamas
Esso Exploration and Production Chad Inc.	100	Bahamas
Esso Exploration and Production Nigeria (Deepwater) Limited	100	Nigeria
Esso Exploration and Production Nigeria (Offshore East) Limited	100	Nigeria
Esso Exploration and Production Nigeria Limited	100	Nigeria
Esso Exploration and Production UK Limited	100	United Kingdom
Esso Exploration Angola (Block 15) Limited	100	Bahamas
Esso Exploration Angola (Block 17) Limited	100	Bahamas
Esso Global Investments Ltd.	100	Bahamas
Esso Italiana S.r.l.	100	Italy
Esso Nederland B.V.	100	Netherlands
Esso Norge AS	100	Norway
Esso Petroleum Company, Limited	100	United Kingdom
Esso Raffinage	82.89	France
Esso Societe Anonyme Francaise	82.89	France
Esso (Thailand) Public Company Limited	65.99	Thailand
Exxon Azerbaijan Limited	100	Bahamas
Exxon Chemical Arabia Inc.	100	Delaware
Exxon Chemical Licensing LLC	100	Delaware
Exxon International Finance Company	100	Delaware
Exxon Mobile Bay Limited Partnership	100	Delaware
Exxon Neftegas Limited	100	Bahamas
Exxon Overseas Corporation	100	Delaware
Exxon Overseas Investment Corporation	100	Delaware
ExxonMobil (China) Investment Co., Ltd.	100	China

1

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
ExxonMobil Abu Dhabi Offshore Petroleum Company Limited	100	Bahamas
ExxonMobil Alaska Production Inc.	100	Delaware
ExxonMobil Asia Pacific Pte. Ltd.	100	Singapore
ExxonMobil Barzan Limited	100	Bahamas
ExxonMobil Canada Ltd.	100	Canada
ExxonMobil Canada Properties	100	Canada
ExxonMobil Canada Resources Company	100	Canada
ExxonMobil Capital Netherlands B.V.	100	Netherlands
ExxonMobil Central Europe Holding GmbH	100	Germany
ExxonMobil Cepu Limited	100	Bermuda
ExxonMobil Chemical France	100	France
ExxonMobil Chemical Limited	100	United Kingdom
ExxonMobil Chemical Operations Private Limited	100	Singapore
ExxonMobil Chemical Services (Shanghai) Co., Ltd.	100	China
ExxonMobil China Petroleum & Petrochemical Company Limited	100	Bahamas
ExxonMobil Development Company	100	Delaware
ExxonMobil Exploration and Production Malaysia Inc.	100	Delaware
ExxonMobil Exploration and Production Norway AS	100	Norway
ExxonMobil Exploration and Production Romania Limited	100	Bahamas
ExxonMobil Exploration and Production Tanzania Limited	100	Bahamas
ExxonMobil Finance Company Limited	100	United Kingdom
ExxonMobil Financial Services B.V.	100	Netherlands
ExxonMobil Gas Marketing Europe Limited	100	United Kingdom
ExxonMobil General Finance Company	100	Delaware
ExxonMobil Global Services Company	100	Delaware
ExxonMobil Holding Company Holland LLC	100	Delaware
ExxonMobil Holding Norway AS	100	Norway
ExxonMobil Hong Kong Limited	100	Hong Kong
ExxonMobil International Finance Company	100	Delaware
ExxonMobil International Services SARL	100	Luxembourg
ExxonMobil Iraq Limited	100	Bahamas
ExxonMobil Italiana Gas S.r.l.	100	Italy
ExxonMobil Kazakhstan Inc.	100	Bahamas
ExxonMobil Kazakhstan Ventures Inc.	100	Delaware
ExxonMobil Lubricants Trading Company	100	Delaware
ExxonMobil Oil Corporation	100	New York
ExxonMobil Pensions-Verwaltungsgesellschaft mbH	100	Germany
ExxonMobil Petroleum & Chemical BVBA	100	Belgium
ExxonMobil Petroleum Finance Company	100	Delaware
ExxonMobil Pipeline Company	100	Delaware
ExxonMobil PNG Limited	100	Papua New Guinea
ExxonMobil Producing Netherlands B.V.	100	Netherlands
ExxonMobil Production Deutschland GmbH	100	Germany
ExxonMobil Production Norway Inc.	100	Delaware
ExxonMobil Qatargas Inc.	100	Delaware
ExxonMobil Qatargas (II) Limited	100	Bahamas

2

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
ExxonMobil Ras Laffan (III) Limited	100	Bahamas
ExxonMobil Rasgas Inc.	100	Delaware
ExxonMobil Research and Engineering Company	100	Delaware
ExxonMobil Russia Kara Sea Holdings B.V.	100	Netherlands
ExxonMobil Sales and Supply LLC	100	Delaware
ExxonMobil Technology Finance Company	100	Delaware
ExxonMobil Ventures Finance Company	100	Delaware
ExxonMobil Ventures Funding Ltd.	100	Bahamas
Fujian Refining & Petrochemical Co. Ltd. (5)	25	China
Golden Pass LNG Terminal Investments LLC	100	Delaware
Golden Pass LNG Terminal LLC (5)	17.6	Delaware
Imperial Oil Limited	69.6	Canada
Imperial Oil (an Ontario General Partnership)	69.6	Canada
Imperial Oil Resources (an Alberta limited partnership)	69.6	Canada
Imperial Oil Resources N.W.T. Limited	69.6	Canada
Imperial Oil Resources Ventures Limited	69.6	Canada
Infineum Holdings B.V. (4) (5)	50	Netherlands
Infineum Italia s.r.l. (4) (5)	50	Italy
Infineum USA L.P. (4) (5)	50	Delaware
Karmorneftegaz Holding SARL (5)	33.33	Luxembourg
Marine Well Containment Company LLC (5)	10	Delaware
McColl-Frontenac Petroleum Inc.	69.6	Canada
Mobil Africa Sales Inc.	100	Delaware
Mobil Australia Resources Company Pty Limited	100	Australia
Mobil California Exploration & Producing Asset Company	100	Delaware
Mobil Caspian Pipeline Company	100	Delaware
Mobil Cerro Negro, Ltd.	100	Bahamas
Mobil Chemical Products International Inc.	100	Delaware
Mobil Corporation	100	Delaware
Mobil Equatorial Guinea Inc.	100	Delaware
Mobil Erdgas-Erdoel GmbH	100	Germany
Mobil Exploration Indonesia Inc.	100	Cayman Islands
Mobil Oil Australia Pty Ltd	100	Australia
Mobil Oil Exploration & Producing Southeast Inc.	100	Delaware
Mobil Oil New Zealand Limited	100	New Zealand
Mobil Producing Nigeria Unlimited	100	Nigeria
Mobil Producing Texas & New Mexico Inc.	100	Delaware
Mobil Yanbu Petrochemical Company Inc.	100	Delaware
Mobil Yanbu Refining Company Inc.	100	Delaware
Mountain Gathering, LLC	100	Delaware
Nederlandse Aardolie Maatschappij B.V. (4) (5)	50	Netherlands
Palmetto Transoceanic LLC	100	Delaware
Papua New Guinea Liquefied Natural Gas Global Company LDC (5)	33.2	Bahamas
Phillips Exploration, LLC	100	Delaware
Qatar Liquefied Gas Company Limited (5)	10	Qatar
Qatar Liquefied Gas Company Limited (2) (5)	24.15	Qatar

3

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Ras Laffan Liquefied Natural Gas Company Limited (5)	24.999	Qatar
Ras Laffan Liquefied Natural Gas Company Limited (II) (5)	30.517	Qatar
Ras Laffan Liquefied Natural Gas Company Limited (3) (5)	30	Qatar
Saudi Aramco Mobil Refinery Company Ltd. (4) (5)	50	Saudi Arabia
Saudi Yanbu Petrochemical Co. (4) (5)	50	Saudi Arabia
SeaRiver Maritime, Inc.	100	Delaware
South Hook LNG Terminal Company Limited (5)	24.15	United Kingdom
Tengizchevroil, LLP (5)	25	Kazakhstan
Terminale GNL Adriatico S.r.l (5)	70.678	Italy
Trend Gathering & Treating, LLC	100	Texas
Wolverine Pipe Line Company	53.39	Delaware
XH, LLC	100	Delaware
XTO Energy Canada	84.80	Canada
XTO Energy Inc.	100	Delaware

______________

NOTES:

(1)	For the purposes of this list, if the registrant owns directly or indirectly approximately 50 percent of the voting securities of any person and approximately 50 percent of the voting securities of such person is owned directly or indirectly by another interest, or if the registrant includes its share of net income of any other unconsolidated person in consolidated net income, such person is deemed to be a subsidiary.
(2)	With respect to certain companies, shares in names of nominees and qualifying shares in names of directors are included in the above percentages.
(3)	The names of other subsidiaries have been omitted from the above list since considered in the aggregate, they would not constitute a significant subsidiary under Securities and Exchange Commission Regulation S-X, Rule 1-02(w).
(4)	The registrant owns directly or indirectly approximately 50 percent of the securities of this person and approximately 50 percent of the voting securities of this person is owned directly or indirectly by another single interest.
(5)	The investment in this unconsolidated person is represented by the registrant's percentage interest in the underlying net assets of such person. The accounting for these unconsolidated persons is referred to as the equity method of accounting.

4

EX-23

 

EXHIBIT 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the following Exxon Mobil Corporation Registration Statements on:

Form S-3 (No. 333-167787)          —        XTO Energy Inc. 2004 Stock Incentive Plan;

Form S-3 (No. 333-194609)          —        Exxon Mobil Corporation Debt Securities;

Form S-8 (Nos. 333-101175,         —        1993 Incentive Program of Exxon Mobil Corporation;

                            333-38917,                      

                            33-51107,

                    and 333-75659)                      

Form S-8 (Nos. 333-145188,         —        2003 Incentive Program of Exxon Mobil Corporation;

                            333-110494,

and 333-183012)

Form S-8 (No. 333-166576)          —        ExxonMobil Savings Plan;

Form S-8 (No. 333-117980)          —        2004 Non-employee Director Restricted Stock Plan;

Form S-8 (No. 333-164620)          —        Post-effective amendment no. 1 on Form S-8 to Form S-4

                                                                        relating to XTO Energy Inc. 1998 Stock Incentive Plan and

                                                                        2004 Incentive Plan

of our report dated February 24, 2016, relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 24, 2016

EX-31.1

 

EXHIBIT 31.1

Certification by Rex W. Tillerson

Pursuant to Securities Exchange Act Rule 13a-14(a) 

I, Rex W. Tillerson, certify that:

1.I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2016	/s/  REX W. TILLERSON
	Rex W. Tillerson
	Chief Executive Officer

EX-31.2

 

EXHIBIT 31.2

Certification by Andrew P. Swiger

Pursuant to Securities Exchange Act Rule 13a-14(a) 

I, Andrew P. Swiger, certify that:

1.I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2016	/s/  ANDREW P. SWIGER
	Andrew P. Swiger
	Senior Vice President
	(Principal Financial Officer)

EX-31.3

 

EXHIBIT 31.3

Certification by David S. Rosenthal

Pursuant to Securities Exchange Act Rule 13a-14(a) 

I, David S. Rosenthal, certify that:

1.I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 24, 2016	/s/  DAVID S. ROSENTHAL
	David S. Rosenthal
	Vice President and Controller
	(Principal Accounting Officer)

EX-32.1

 

EXHIBIT 32.1

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

        For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Rex W. Tillerson, the chief executive officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(i)the Annual Report on Form 10-K of the Company for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2016	/s/  REX W. TILLERSON
	Rex W. Tillerson
	Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

 

EXHIBIT 32.2

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

        For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Andrew P. Swiger, the principal financial officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(i)the Annual Report on Form 10-K of the Company for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2016	/s/  ANDREW P. SWIGER
	Andrew P. Swiger
	Senior Vice President
	(Principal Financial Officer)

A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

 

EXHIBIT 32.3

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

        For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, David S. Rosenthal, the principal accounting officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(i)the Annual Report on Form 10-K of the Company for the year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 24, 2016	/s/  DAVID S. ROSENTHAL
	David S. Rosenthal
	Vice President and Controller
	(Principal Accounting Officer)

A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2015
Trading Symbol	XOM
Entity Registrant Name	EXXON MOBIL CORP
Entity Central Index Key	0000034088
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		4,152,756,609
Entity Public Float			$ 346

XML

Consolidated Statement Of Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other income
Sales and other operating revenue	[1],[2]	$ 259,488	$ 394,105	$ 420,836
Income from equity affiliates		7,644	13,323	13,927
Other income		1,750	4,511	3,492
Total revenues and other income		268,882	411,939	438,255
Costs and other deductions
Crude oil and product purchases		130,003	225,972	244,156
Production and manufacturing expenses		35,587	40,859	40,525
Selling, general and administrative expenses		11,501	12,598	12,877
Depreciation and depletion		18,048	17,297	17,182
Exploration expenses, including dry holes		1,523	1,669	1,976
Interest expense		311	286	9
Sales-based taxes	[1]	22,678	29,342	30,589
Other taxes and duties		27,265	32,286	33,230
Total costs and other deductions		246,916	360,309	380,544
Income before income taxes		21,966	51,630	57,711
Income taxes		5,415	18,015	24,263
Net income including noncontrolling interests		16,551	33,615	33,448
Net income attributable to noncontrolling interests		401	1,095	868
Net income attributable to ExxonMobil		$ 16,150	$ 32,520	$ 32,580
Earnings per common share (dollars)	[3]	$ 3.85	$ 7.6	$ 7.37
Earnings per common share - assuming dilution (dollars)		$ 3.85	$ 7.6	$ 7.37

[1] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

[2] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

[3] The earnings per common share and earnings per common share - assuming dilution are the same in each period shown.

XML

Consolidated Statement Of Income (Parenthetical) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statement Of Income [Abstract]
Sales-based taxes included in sales and other operating revenue	[1]	$ 22,678	$ 29,342	$ 30,589

[1] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

XML

Consolidated Statement Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statement Of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 16,551	$ 33,615	$ 33,448
Other comprehensive income (net of income taxes)
Foreign exchange translation adjustment	(9,303)	(5,847)	(3,620)
Adjustment for foreign exchange translation (gain)/loss included in net income	(14)	152	(23)
Postretirement benefits reserves adjustment (excluding amortization)	2,358	(4,262)	3,174
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	1,448	1,111	1,820
Unrealized change in fair value of stock investments	33	(63)
Realized (gain)/ loss from stock investments included in net income	27	3
Total other comprehensive income	(5,451)	(8,906)	1,351
Comprehensive income including noncontrolling interests	11,100	24,709	34,799
Comprehensive income attributable to noncontrolling interests	(496)	421	760
Comprehensive income attributable to ExxonMobil	$ 11,596	$ 24,288	$ 34,039

XML

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 3,705	$ 4,616
Cash and cash equivalents - restricted		42
Notes and accounts receivable, less estimated doubtful amounts	19,875	28,009
Inventories
Crude oil, products and merchandise	12,037	12,384
Materials and supplies	4,208	4,294
Other current assets	2,798	3,565
Total current assets	42,623	52,910
Investments, advances and long-term receivables	34,245	35,239
Property, plant and equipment, at cost, less accumulated depreciation and depletion	251,605	252,668
Other assets, including intangibles, net	8,285	8,676
Total assets	336,758	349,493
Current liabilities
Notes and loans payable	18,762	17,468
Accounts payable and accrued liabilities	32,412	42,227
Income taxes payable	2,802	4,938
Total current liabilities	53,976	64,633
Long-term debt	19,925	11,653
Postretirement benefits reserves	22,647	25,802
Deferred income tax liabilities	36,818	39,230
Long-term obligations to equity companies	5,417	5,325
Other long-term obligations	21,165	21,786
Total liabilities	$ 159,948	$ 168,429
Commitments and contingencies (Note 16)
Equity
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued)	$ 11,612	$ 10,792
Earnings reinvested	412,444	408,384
Accumulated other comprehensive income	(23,511)	(18,957)
Common stock held in treasury (3,863 million shares in 2015 and 3,818 million shares in 2014)	(229,734)	(225,820)
ExxonMobil share of equity	170,811	174,399
Noncontrolling interests	5,999	6,665
Total equity	176,810	181,064
Total liabilities and equity	$ 336,758	$ 349,493

XML

Consolidated Balance Sheet (Parenthetical) - $ / shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
Consolidated Balance Sheet [Abstract]
Common stock, without par value
Common stock, shares authorized	9,000	9,000
Common stock, shares issued	8,019	8,019
Common stock held in treasury, shares	3,863	3,818

XML

Consolidated Statement Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income including noncontrolling interests	$ 16,551	$ 33,615	$ 33,448
Adjustments for noncash transactions
Depreciation and depletion	18,048	17,297	17,182
Deferred income tax charges/(credits)	(1,832)	1,540	754
Postretirement benefits expense in excess of/(less than) net payments	2,153	524	2,291
Other long-term obligation provisions in excess of/(less than) payments	(380)	1,404	(2,566)
Dividends received greater than/(less than) equity in current earnings of equity companies	(691)	(358)	3
Changes in operational working capital, excluding cash and debt
Reduction/(increase) - Notes and accounts receivable	4,692	3,118	(305)
Reduction/(increase) - Inventories	(379)	(1,343)	(1,812)
Reduction/(increase) - Other current assets	45	(68)	(105)
Increase/(reduction) - Accounts and other payables	(7,471)	(6,639)	(2,498)
Net (gain) on asset sales	(226)	(3,151)	(1,828)
All other items - net	(166)	(823)	350
Net cash provided by operating activities	30,344	45,116	44,914
Cash flows from investing activities
Additions to property, plant and equipment	(26,490)	(32,952)	(33,669)
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments	2,389	4,035	2,707
Decrease/(increase) in restricted cash and cash equivalents	42	227	72
Additional investments and advances	(607)	(1,631)	(4,435)
Collection of advances	842	3,346	1,124
Net cash used in investing activities	(23,824)	(26,975)	(34,201)
Cash flows from financing activities
Additions to long-term debt	8,028	5,731	345
Reductions in long-term debt	(26)	(69)	(13)
Additions to short-term debt			16
Reductions in short-term debt	(506)	(745)	(756)
Additions/(reductions) in commercial paper, and debt with three months or less maturity	1,759	2,049	12,012
Cash dividends to ExxonMobil shareholders	(12,090)	(11,568)	(10,875)
Cash dividends to noncontrolling interests	(170)	(248)	(304)
Changes in noncontrolling interests			(1)
Tax benefits related to stock-based awards	2	115	48
Common stock acquired	(4,039)	(13,183)	(15,998)
Common stock sold	5	30	50
Net cash used in financing activities	(7,037)	(17,888)	(15,476)
Effects of exchange rate changes on cash	(394)	(281)	(175)
Increase/(decrease) in cash and cash equivalents	(911)	(28)	(4,938)
Cash and cash equivalents at beginning of year	4,616	4,644	9,582
Cash and cash equivalents at end of year	$ 3,705	$ 4,616	$ 4,644

XML

Consolidated Statement Of Changes In Equity - USD ($) shares in Millions, $ in Millions	Total	ExxonMobil Share Of Common Stock [Member]	ExxonMobil Share Of Earnings Reinvested [Member]	ExxonMobil Share Of Accumulated Other Comprehensive Income [Member]	ExxonMobil Share Of Common Stock Held In Treasury [Member]	ExxonMobil Share Of Equity [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2012	$ 171,660	$ 9,653	$ 365,727	$ (12,184)	$ (197,333)	$ 165,863	$ 5,797
Balance (in shares) - issued at Dec. 31, 2012	8,019
Balance (in shares) - in treasury at Dec. 31, 2012	3,517
Balance (in shares) - outstanding at Dec. 31, 2012	4,502
Amortization of stock-based awards	$ 761	761				761
Tax benefits related to stock-based awards	162	162				162
Other	(259)	(499)				(499)	240
Net income for the year	33,448		32,580			32,580	868
Dividends - common shares (company)			(10,875)			(10,875)
Dividends - common shares (NCI)							(304)
Dividends - common shares (total)	(11,179)
Other comprehensive income	1,351			1,459		1,459	(108)
Acquisitions, at cost (company)					(15,998)	(15,998)
Acquisitions, at cost (NCI)							(1)
Acquisitions, at cost (total)	(15,999)
Dispositions	$ 550				550	550
Acquisitions (in shares)	(177)
Dispositions (in shares)	10
Balance at Dec. 31, 2013	$ 180,495	10,077	387,432	(10,725)	(212,781)	174,003	6,492
Balance (in shares) - issued at Dec. 31, 2013	8,019
Balance (in shares) - in treasury at Dec. 31, 2013	3,684
Balance (in shares) - outstanding at Dec. 31, 2013	4,335
Amortization of stock-based awards	$ 780	780				780
Tax benefits related to stock-based awards	49	49				49
Other	(114)	(114)				(114)
Net income for the year	33,615		32,520			32,520	1,095
Dividends - common shares (company)			(11,568)			(11,568)
Dividends - common shares (NCI)							(248)
Dividends - common shares (total)	(11,816)
Other comprehensive income	(8,906)			(8,232)		(8,232)	(674)
Acquisitions, at cost (company)					(13,183)	(13,183)
Acquisitions, at cost (total)	(13,183)
Dispositions	$ 144				144	144
Acquisitions (in shares)	(136)
Dispositions (in shares)	2
Balance at Dec. 31, 2014	$ 181,064	10,792	408,384	(18,957)	(225,820)	174,399	6,665
Balance (in shares) - issued at Dec. 31, 2014	8,019
Balance (in shares) - in treasury at Dec. 31, 2014	3,818
Balance (in shares) - outstanding at Dec. 31, 2014	4,201
Amortization of stock-based awards	$ 828	828				828
Tax benefits related to stock-based awards	116	116				116
Other	(124)	(124)				(124)
Net income for the year	16,551		16,150			16,150	401
Dividends - common shares (company)			(12,090)			(12,090)
Dividends - common shares (NCI)							(170)
Dividends - common shares (total)	(12,260)
Other comprehensive income	(5,451)			(4,554)		(4,554)	(897)
Acquisitions, at cost (company)					(4,039)	(4,039)
Acquisitions, at cost (total)	(4,039)
Dispositions	$ 125				125	125
Acquisitions (in shares)	(48)
Dispositions (in shares)	3
Balance at Dec. 31, 2015	$ 176,810	$ 11,612	$ 412,444	$ (23,511)	$ (229,734)	$ 170,811	$ 5,999
Balance (in shares) - issued at Dec. 31, 2015	8,019
Balance (in shares) - in treasury at Dec. 31, 2015	3,863
Balance (in shares) - outstanding at Dec. 31, 2015	4,156

XML

Summary Of Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary Of Accounting Policies [Abstract]

Summary Of Accounting Policies

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the 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 included in “Investments, advances and long-term receivables.” The Corporation’s share of the net income of these companies is included in the Consolidated Statement 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 indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in Accumulated Other 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 if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

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

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

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as 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 Statement of 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 activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives 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 underlying 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 participants. 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 prices in active markets for identical assets or liabilities. Hierarchy Level2 inputs are inputs other than quoted prices included within Level1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 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 last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

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

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.

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-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using 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 transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used.

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

The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for this assessment.

Potential trigger events for impairment evaluation include:

• a significant decrease in the market price of a long-lived asset;
• a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;
• a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
• an accumulation of project costs significantly in excess of the amount originally expected;
• a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
• a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

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

If there were a trigger event, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

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

Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any 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 carrying value.

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

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. 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 estimated. 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 of the 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 inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-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 units. 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.

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Accounting Changes

12 Months Ended

Dec. 31, 2015

Accounting Changes [Abstract]

Accounting Changes

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2015 that had a material impact on the Corporation’s financial statements.

In May 2014, the Financial Accounting Standards Board issued a new standard, Revenue from Contracts with Customers. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry specific requirements, and expands disclosure requirements. The standard is required to be adopted beginning January 1, 2018.

“Sales and Other Operating Revenue” on the Consolidated Statement of Income includes sales, excise and value-added taxes on sales transactions. When the Corporation adopts the standard, revenue will exclude sales-based taxes collected on behalf of third parties. This change in reporting will not impact earnings.

The Corporation continues to evaluate other areas of the standard and its effect on the Corporation’s financial statements.

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Miscellaneous Financial Information

12 Months Ended

Dec. 31, 2015

Miscellaneous Financial Information [Abstract]

Miscellaneous Financial Information

3. Miscellaneous Financial Information

Research and development expenses totaled $1,008 million in 2015, $971 million in 2014 and $1,044 million in 2013.

Net income included before-tax aggregate foreign exchange transaction losses of $119 million and $225 million in 2015 and 2014, respectively, and gains of $155 million in 2013.

In 2015, 2014 and 2013, net income included a loss of $186 million, and gains of $187 million and $282 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $4.5 billion and $10.6 billion at December 31, 2015, and 2014, respectively.

Crude oil, products and merchandise as of year-end 2015 and 2014 consist of the following:

		2015	2014
		(billions of dollars)
Crude oil		4.2	4.6
Petroleum products		4.1	4.1
Chemical products		2.7	2.9
Gas/other		1.0	0.8
	Total	12.0	12.4

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Other Comprehensive Income Information

12 Months Ended

Dec. 31, 2015

Other Comprehensive Income Information [Abstract]

Other Comprehensive Income Information

4.Other Comprehensive Income Information

		Cumulative	Post-
		Foreign	retirement	Unrealized
		Exchange	Benefits	Change in
ExxonMobil Share of Accumulated Other		Translation	Reserves	Stock
Comprehensive Income		Adjustment	Adjustment	Investments	Total
		(millions of dollars)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(3,233)	2,963	-	(270)
Amounts reclassified from accumulated other
	comprehensive income	(23)	1,752	-	1,729
Total change in accumulated other comprehensive income		(3,256)	4,715	-	1,459
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(5,258)	(4,132)	(63)	(9,453)
Amounts reclassified from accumulated other
	comprehensive income	152	1,066	3	1,221
Total change in accumulated other comprehensive income		(5,106)	(3,066)	(60)	(8,232)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(8,204)	2,202	33	(5,969)
Amounts reclassified from accumulated other
	comprehensive income	(14)	1,402	27	1,415
Total change in accumulated other comprehensive income		(8,218)	3,604	60	(4,554)
Balance as of December 31, 2015		(14,170)	(9,341)	-	(23,511)

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2015	2014	2013
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	14	(152)	23
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(2,066)	(1,571)	(2,616)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(42)	(5)	-

(1)These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 17 – Pension and Other Postretirement Benefits for additional details.)

Income Tax (Expense)/Credit For
Components of Other Comprehensive Income		2015	2014	2013
		(millions of dollars)
Foreign exchange translation adjustment		170	292	218
Postretirement benefits reserves adjustment (excluding amortization)		(1,192)	2,009	(1,540)
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(618)	(460)	(796)
Unrealized change in fair value of stock investments		(17)	34	-
Realized change in fair value of stock investments included in net income		(15)	(2)	-
Total		(1,672)	1,873	(2,118)

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Cash Flow Information

12 Months Ended

Dec. 31, 2015

Cash Flow Information [Abstract]

Cash Flow Information

5. Cash Flow Information

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

For 2015, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows includes before-taxamounts from the sale of service stations in Europe, the sale of Upstream properties in the U.S., the sale of ExxonMobil’s interests in Chemical and Refining joint ventures, and thepending sale of the Torrance refinery. For 2014, the amount includes before-tax gains from the sale of Hong Kong power operations, additional proceeds related to the 2013 sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale or exchange of Upstream properties in the U.S., Canada, and Malaysia. For 2013, the amount includes before-tax gains from the sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale of service stations. These net gains are reported in “Other income” on the Consolidated Statement of Income.

In 2015, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $358 million addition of commercial paper with maturity over three months. The gross amount issued was $8.1 billion, while the gross amount repaid was $7.7 billion.

In 2015, ExxonMobil completed an asset exchange that resulted in value received of approximately $500 million including $100 million in cash. The non-cash portion was not included in the “Sales of subsidiaries, investments, and property, plant and equipment” or the “All other items-net” lines on the Statement of Cash Flows. Capital leases of approximately $1 billion were not included in the “Additions to long-term debt” or “Additions to property, plant and equipment” lines on the Statement of Cash Flows.

In 2014, ExxonMobil completed asset exchanges, primarily non-cash transactions, of approximately $1.2 billion. This amount is not included in the “Sales of subsidiaries, investments, and property, plant and equipment” or the “Additions to property, plant and equipment” lines on the Statement of Cash Flows.

	2015	2014	2013
	(millions of dollars)
Cash payments for interest	586	380	426
Cash payments for income taxes	7,269	18,085	25,066

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Additional Working Capital Information

12 Months Ended

Dec. 31, 2015

Additional Working Capital Information [Abstract]

Additional Working Capital Information

6. Additional Working Capital Information

			Dec. 31	Dec. 31
			2015	2014
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $107 million and $113 million		13,243	18,541
	Other, less reserves of $4 million and $48 million		6,632	9,468
		Total	19,875	28,009
Notes and loans payable
	Bank loans		231	473
	Commercial paper		17,973	16,225
	Long-term debt due within one year		558	770
		Total	18,762	17,468
Accounts payable and accrued liabilities
	Trade payables		18,074	25,286
	Payables to equity companies		4,639	6,589
	Accrued taxes other than income taxes		2,937	3,290
	Other		6,762	7,062
		Total	32,412	42,227

The Corporation has short-term committed lines of credit of $6.0 billion which were unused as of December 31, 2015. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was0.4percent and 0.3 percent at December31,2015, and 2014, respectively.

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Equity Company Information

12 Months Ended

Dec. 31, 2015

Equity Company Information [Abstract]

Equity Company Information

7.Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1).These companies are primarily engaged in oil and gas exploration and production, and natural gas marketing in North America; natural gas exploration, production and distribution, and downstream operations in Europe; and exploration, production, liquefied natural gas (LNG) operations, refining operations, petrochemical manufacturing, and fuel sales 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 between 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 practicable to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “income from equity affiliates.”

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 15 percent, 14 percent and 13 percent in the years 2015, 2014 and 2013, respectively.

In 2013 and 2014, the Corporation and Rosneft established various entities to conduct exploration and research activities. Periods of disproportionate funding will result in the Corporation recognizing, during the early phases of the projects, an investment that is larger than its equity share in these entities. These joint ventures are considered Variable Interest Entities. However, since the Corporation is not the primary beneficiary of these entities, the joint ventures are reported as equity companies. In 2014, the European Union and United States imposed sanctions relating to the Russian energy sector. With respect to the foregoing, each joint venture continues to comply with all applicable laws, rules and regulations. The Corporation's maximum before-tax exposure to loss from these joint ventures as of December 31, 2015, is $1.0 billion.

		2015			2014			2013
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		111,866		34,297	183,708		55,855	236,161		68,084
Income before income taxes		36,379		10,670	65,549		19,014	69,454		19,999
Income taxes		11,048		3,019	20,520		5,684	21,618		6,069
	Income from equity affiliates	25,331		7,651	45,029		13,330	47,836		13,930
Current assets		32,879		11,244	49,905		16,802	62,398		19,545
Long-term assets		109,684		32,878	110,754		33,619	116,450		35,695
	Total assets	142,563		44,122	160,659		50,421	178,848		55,240
Current liabilities		22,947		6,738	37,333		11,472	54,550		15,243
Long-term liabilities		60,388		17,165	66,231		19,470	68,857		20,873
	Net assets	59,228		20,219	57,095		19,479	55,441		19,124

A list of significant equity companies as of December 31, 2015, 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
Cross Timbers Energy, LLC	50
Golden Pass LNG Terminal LLC	18
Karmorneftegaz Holding SARL	33
Marine Well Containment Company LLC	10
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
Downstream
Fujian Refining & Petrochemical Co. Ltd.	25
Saudi Aramco Mobil Refinery Company Ltd.	50
Chemical
Al-Jubail Petrochemical Company	50
Infineum Holdings B.V.	50
Infineum Italia s.r.l.	50
Infineum USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

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Investments, Advances And Long-Term Receivables

12 Months Ended

Dec. 31, 2015

Investments, Advances And Long-Term Receivables [Abstract]

Investments, Advances And Long-Term Receivables

8. Investments, Advances and Long-Term Receivables

			Dec. 31,	Dec. 31,
			2015	2014
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,337	20,017
	Advances		9,110	9,818
		Total equity company investments and advances	29,447	29,835
Companies carried at cost or less and stock investments carried at fair value			274	526
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $3,040 million and $2,662 million		4,524	4,878
		Total	34,245	35,239

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Property, Plant And Equipment And Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Property, Plant And Equipment And Asset Retirement Obligations [Abstract]

Property, Plant And Equipment And Asset Retirement Obligations

9. Property, Plant and Equipment and Asset Retirement Obligations

		December 31, 2015		December 31, 2014
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,821	203,822	347,170	205,308
Downstream		50,742	21,330	53,327	22,639
Chemical		32,481	16,247	30,717	14,918
Other		16,293	10,206	15,575	9,803
	Total	447,337	251,605	446,789	252,668

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

The Corporation periodically reviews the estimated asset service life of its property, plant and equipment. Effective January 1, 2016, the Corporation revised the estimated asset service life of its investments in process equipment in the Chemical segment to 25 years.This revision will not have a material impact on the Corporation’s financial statements.

Accumulated depreciation and depletion totaled $195,732 million at the end of 2015 and $194,121 million at the end of 2014. Interest capitalized in 2015, 2014 and 2013 was $482 million, $344 million and $309 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, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value.

Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on 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 future settlement dates of such obligations.

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

		2015	2014
		(millions of dollars)
Beginning balance		13,424	12,988
	Accretion expense and other provisions	775	871
	Reduction due to property sales	(208)	(151)
	Payments made	(928)	(724)
	Liabilities incurred	283	122
	Foreign currency translation	(931)	(908)
	Revisions	1,289	1,226
Ending balance		13,704	13,424

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Accounting For Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2015

Accounting For Suspended Exploratory Well Costs [Abstract]

Accounting For Suspended Exploratory Well Costs

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 completion as a producing well and the Corporationis making sufficient progress assessing the reserves and the economic and operating viability of the project. 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 government payment 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 costs.

Change in capitalized suspended exploratory well costs:

			2015	2014	2013
			(millions of dollars)
Balance beginning at January 1			3,587	2,707	2,679
	Additions pending the determination of proved reserves		847	1,095	293
	Charged to expense		(5)	(28)	(52)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(43)	(160)	(107)
	Divestments/Other		(14)	(27)	(106)
Ending balance at December 31			4,372	3,587	2,707
Ending balance attributed to equity companies included above			696	645	13

Period end capitalized suspended exploratory well costs:

			2015	2014	2013
			(millions of dollars)
Capitalized for a period of one year or less			847	1,095	293
	Capitalized for a period of between one and five years		2,386	1,659	1,705
	Capitalized for a period of between five and ten years		826	544	470
	Capitalized for a period of greater than ten years		313	289	239
Capitalized for a period greater than one year - subtotal			3,525	2,492	2,414
		Total	4,372	3,587	2,707

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months, which includes the Rosneft joint venture exploration activity (refer to the relevant portion of Note 7).

			2015	2014	2013
Number of projects with first capitalized well drilled in the preceding 12 months			4	8	8
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		55	53	50
		Total	59	61	58

Of the 55 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2015, 18 projects have drilling in the preceding 12 months or exploratory activity either planned in the next two years or subject to sanctions. The remaining 37 projects are those with completed exploratory activity progressing toward development.

The table below provides additional detail for those 37 projects, which total $1,154 million.

			Years
		Dec. 31,	Wells
Country/Project		2015	Drilled	Comment
	(millions of dollars)
Angola
- Kaombo Split Hub Phase 2		20	2005 - 2006	Evaluating development plan to tie into planned production facilities.
- Perpetua-Zinia-Acacia		15	2008 - 2009	Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure.
Australia
- East Pilchard		7	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		11	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		34	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Canada
- Horn River		241	2009 - 2012	Evaluating development alternatives to tie into planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		29	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.
- Kalamkas		18	2006 - 2009	Evaluating development alternatives, while continuing discussions with the
				government regarding development plan.
Malaysia
- 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.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Pegi		32	2009	Awaiting capacity in existing/planned infrastructure.
- Satellite Field		12	2013	Evaluating development plan to tie into planned production facilities.
Development Phase 2
- Other (4 projects)		14	2002	Evaluating and pursuing development of several additional discoveries.
Norway
- Gamma		13	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		15	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		25	2008 - 2014	Evaluating development plans, including potential for tieback to existing production
				facilities.
Papua New Guinea
- Juha		28	2007	Progressing development plans to tie into existing 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
- Hadrian North		209	2010 - 2013	Evaluating development plan to tie into existing production facilities.
- Tip Top		31	2009	Evaluating development concept and requisite facility upgrades.
Total 2015 (37 projects)		1,154

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Leased Facilities

12 Months Ended

Dec. 31, 2015

Leased Facilities [Abstract]

Leased Facilities

11. Leased Facilities

At December 31, 2015, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $4,877 million as indicated in the table. Estimated related rental income from noncancelable subleases is $32 million.

	Lease Payments Under Minimum Commitments			Related
	Drilling Rigs			Sublease
	and Related			Rental
	Equipment	Other	Total	Income
	(millions of dollars)
2016	827	826	1,653	7
2017	408	595	1,003	6
2018	134	421	555	2
2019	89	255	344	2
2020	77	188	265	2
2021 and beyond	86	971	1,057	13
Total	1,621	3,256	4,877	32

Net rental cost under both cancelable and noncancelable operating leases incurred during 2015, 2014 and 2013 were as follows:

			2015	2014	2013
			(millions of dollars)
Rental cost
	Drilling rigs and related equipment		1,853	1,763	1,424
	Other		2,120	2,314	2,417
		Total	3,973	4,077	3,841
	Less sublease rental income		44	52	44
Net rental cost			3,929	4,025	3,797

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Earnings Per Share

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share

12. Earnings Per Share

	2015	2014	2013
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	16,150	32,520	32,580
Weighted average number of common shares outstanding(millions of shares)	4,196	4,282	4,419
Earnings per common share(dollars) (1)	3.85	7.60	7.37
Dividends paid per common share (dollars)	2.88	2.70	2.46

(1)The earnings per common share and earnings per common share - assuming dilution are the same in each period shown.

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Financial Instruments And Derivatives

12 Months Ended

Dec. 31, 2015

Financial Instruments And Derivatives [Abstract]

Financial Instruments And Derivatives

13. Financial Instruments and Derivatives

Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, excluding capitalized lease obligations, was $18.9 billion and $11.7 billion at December 31, 2015, and 2014, respectively, as compared to recorded book values of $18.7 billion and $11.3 billion at December 31, 2015, and 2014, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $8.0 billion of long-term debt in the first quarter of 2015.

The fair value of long-term debt by hierarchy level at December 31, 2015, is: Level 1 $18,584 million; Level 2 $208 million; and Level 3 $62 million.

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

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net asset of $21 million at year-end 2015 and a net asset of $75 million at year-end 2014. Assets and liabilities associated with derivatives are usually recorded either in “Other current assets” or “Accounts payable and accrued liabilities.”

The Corporation’s fair value measurement of its derivative instruments use either Level 1 or Level 2 inputs.

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $39 million, $110 million and $(7) million during 2015, 2014 and 2013, respectively. Income statement effects associated with derivatives are usually recorded either in “Sales and other operating revenue” or “Crude oil 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 result of the derivative activities described above.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Long-Term Debt [Abstract]

Long-Term Debt

14. Long-Term Debt

At December 31, 2015, long-term debt consisted of $19,217 million due in U.S. dollars and $708 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $558 million, which matures within one year and is included in current liabilities. The increase in the book value of long-term debt reflects the Corporation’s issuance of $8.0 billion of long-term debt in the first quarter of 2015.The amounts of long-term debt, including capitalized lease obligations, maturing in each of the four years after December 31, 2016, in millions of dollars, are: 2017 – $2,959; 2018 – $2,967; 2019 –$2,374; and 2020 –$1,602. At December 31, 2015, the Corporation’s unused long-term credit lines were $0.4 billion.

Summarized long-term debt at year-end 2015 and 2014 are shown in the table below:

			2015	2014
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	1,500
	Floating-rate notes due 2017 (1)		750	750
	Floating-rate notes due 2018 (2)		500	-
	1.305% notes due 2018		1,600	-
	1.819% notes due 2019		1,750	1,750
	Floating-rate notes due 2019 (3)		500	500
	1.912% notes due 2020		1,500	-
	2.397% notes due 2022		1,150	-
	Floating-rate notes due 2022 (4)		500	-
	3.176% notes due 2024		1,000	1,000
	2.709% notes due 2025		1,750	-
	3.567% notes due 2045		1,000	-
XTO Energy Inc. (5)
	5.650% senior notes due 2016		-	207
	6.250% senior notes due 2017		465	477
	5.500% senior notes due 2018		377	383
	6.500% senior notes due 2018		463	474
	6.100% senior notes due 2036		198	199
	6.750% senior notes due 2037		307	309
	6.375% senior notes due 2038		235	236
Mobil Producing Nigeria Unlimited (6)
	Variable notes due 2016-2019		101	399
Esso (Thailand) Public Company Ltd.(7)
	Variable notes due 2016-2020		83	121
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2017-2051 (8)			2,611	2,611
Other U.S. dollar obligations (9)			97	104
Other foreign currency obligations			1	9
Capitalized lease obligations(10)			1,238	375
		Total long-term debt	19,925	11,653

(1)Average effective interest rate of 0.3% in 2015 and 0.3% in 2014.

(2)Average effective interest rate of 0.4% in 2015.

(3) Average effective interest rate of 0.5% in 2015 and 0.4% in 2014.

(4) Average effective interest rate of 0.7% in 2015.

(5)Includes premiums of $179 millionin 2015 and $219 million in 2014.

(6)Average effective interest rate of 4.6% in 2015 and 4.5% in 2014.

(7)Average effective interest rate of 2.1% in 2015 and 2.4% in 2014.

(8)Average effective interest rate of 0.02% in 2015 and 0.03% in 2014.

(9)Average effective interest rate of 3.8% in 2015 and 4.2% in 2014.

(10)Average imputed interest rate of 9.2% in 2015 and 7.0% in 2014.

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Incentive Program

12 Months Ended

Dec. 31, 2015

Incentive Program [Abstract]

Incentive Program

15. Incentive Program

The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions 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 grant and 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. Awards that 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 awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2015, remaining shares available for award under the 2003 Incentive Program were 100million.

Restricted Stock and Restricted Stock Units. Awards totaling 9,681 thousand, 9,775 thousand, and 9,729thousandof restricted (nonvested) common stock units were granted in 2015, 2014 and 2013, respectively. Compensation expense for these awards is based on 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 employees from 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. During the 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 vesting 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. Awards 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 occurs 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 plans and 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, 2015.

	2015
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	44,439		81.45
2014 award issued in 2015	9,758		95.20
Vested	(9,945)		79.86
Forfeited	(189)		82.26
Issued and outstanding at December 31	44,063		84.85

Value of restricted stock and units	2015	2014	2013
Grant price (dollars)	81.27	95.20	94.47
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	727	858	843
Units settled in cash	60	73	76
Total value	787	931	919

As of December 31, 2015, there was $2,222 million of unrecognized compensation cost related to the nonvested restricted awards. This costis expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted stock units was $855 million, $831million and$854 million for 2015, 2014 and 2013, respectively. The income taxbenefit recognized in income related to this compensation expensewas $78million, $76 million and $78 million for the same periods, respectively. The fair value of shares and units vested in 2015,2014 and 2013 was $808 million, $946 million and $1,040 million, respectively. Cash payments of $64 million, $73 million and $67 million for vested restricted stock units settled in cash were made in 2015, 2014 and 2013, respectively.

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Litigation And Other Contingencies

12 Months Ended

Dec. 31, 2015

Litigation And Other Contingencies [Abstract]

Litigation And Other Contingencies

16. Litigation and Other Contingencies

Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount 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 amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters as well as other matters which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the 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 December31,2015, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar mattersdo not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure.

						Dec. 31, 2015
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			98		35	133
	Other			2,539		4,553	7,092
		Total		2,637		4,588	7,225
(1) ExxonMobil share.

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

	Payments Due by Period
		2017-	2021 and
	2016	2020	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	133	493		310	936

(1) Undiscounted obligations of $936million mainly pertain to pipeline throughput agreements and include $411million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $144million, totaled $792million.

In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an 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 for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID). The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. On October 9, 2014, the ICSID Tribunal issued its final award finding in favor of the ExxonMobil affiliates and awarding $1.6 billion as of the date of expropriation, June 27, 2007, and interest from that date at 3.25% compounded annually until the date of payment in full. The Tribunal also noted that one of the Cerro Negro Project agreements provides a mechanism to prevent double recovery between the ICSID award and all or part of an earlier award of $908 million to an ExxonMobil affiliate, Mobil Cerro Negro, Ltd., against PdVSA and a PdVSA affiliate, PdVSA CN, in an arbitration under the rules of the International Chamber of Commerce.

On June 12, 2015, the Tribunal rejected in its entirety Venezuela’s October 23, 2014, application to revise the ICSID award. The Tribunal also lifted the associated stay of enforcement that had been entered upon the filing of the application to revise.

Still pending is Venezuela’s February 2, 2015, application to ICSID seeking annulment of the ICSID award. That application alleges that, in issuing the ICSID award, the Tribunal exceeded its powers, failed to state reasons on which the ICSID award was based, and departed from a fundamental rule of procedure. A separate stay of the ICSID award was entered following the filing of the annulment application. On July 7, 2015, the ICSID Committee considering the annulment application heard arguments from the parties on whether to lift the stay of the award associated with that application. On July 28, 2015, the Committee issued an order that would lift the stay of enforcement unless, within 30 days, Venezuela delivered a commitment to pay the award if the application to annul is denied. On September 17, 2015, the Committee ruled that Venezuela had complied with the requirement to submit a written commitment to pay the award and so left the stay of enforcement in place. A hearing on Venezuela’s application for annulment, previously scheduled for January 25-27, 2016, has been rescheduled for March 8-9, 2016.

The United States District Court for the Southern District of New York entered judgment on the ICSID award on October 10, 2014. Motions filed by Venezuela to vacate that judgment on procedural grounds and to modify the judgment by reducing the rate of interest to be paid on the ICSID award from the entry of the court’s judgment, until the date of payment, were denied on February 13, 2015, and March 4, 2015, respectively. On March 9, 2015, Venezuela filed a notice of appeal of the court’s actions on the two motions. Oral arguments on this appeal were held before the United States Court of Appeals for the Second Circuit on January 7, 2016.

The District Court’s judgment on the ICSID award is currently stayed until such time as ICSID’s stay of the award entered following Venezuela’s filing of its application to annul has been lifted. The net impact of these matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material 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 Corporation (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 percent 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 of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors' position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Nigerian 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 award. The Contractors appealed that judgment to the Court of Appeal, Abuja Judicial Division. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in order to preserve their ability to seek enforcement of the PSC in the courts if necessary. In October 2014, the Contractors filed suit in the United States District Court for the Southern District of New York to enforce, if necessary, the arbitration award against NNPC assets residing within that jurisdiction. NNPC has moved to dismiss the lawsuit. Proceedings in the Southern District of New York are currently stayed. At this time, the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation's operations or financial condition.

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Pension And Other Postretirement Benefits

12 Months Ended

Dec. 31, 2015

Pension And Other Postretirement Benefits [Abstract]

Pension And Other Postretirement Benefits

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 Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.25	4.00	3.60	3.10	4.25	4.00
	Long-term rate of compensation increase	5.75	5.75	4.80	5.30	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	20,529	17,304	30,047	27,357	9,436	7,868
	Service cost	864	677	689	590	170	140
	Interest cost	785	807	850	1,138	346	383
	Actuarial loss/(gain)	(545)	3,192	(1,517)	4,929	(617)	1,522
	Benefits paid (1) (2)	(2,050)	(1,427)	(1,287)	(1,366)	(482)	(525)
	Foreign exchange rate changes	-	-	(3,242)	(2,540)	(106)	(48)
	Amendments, divestments and other	-	(24)	(423)	(61)	(465)	96
Benefit obligation at December 31		19,583	20,529	25,117	30,047	8,282	9,436
Accumulated benefit obligation at December 31		15,666	16,385	22,362	26,318	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2015 and 2014, other postretirement benefits paid are net of $15 million and $21 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 discount rate determined by use of a yield curve based on high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments.For major non-U.S. plans, the discount rateis determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, 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 2017 and subsequent years. A one-percentage-point increase in thehealth care cost trend rate would increase service and interest cost by $88 million and the postretirement benefit obligation by $963 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $66million and the postretirement benefit obligation by $764 million.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Change in plan assets
	Fair value at January 1	12,915	11,190	20,095	19,283	468	620
	Actual return on plan assets	(307)	1,497	918	3,153	-	41
	Foreign exchange rate changes	-	-	(2,109)	(1,738)	-	-
	Company contribution	-	1,476	515	554	42	31
	Benefits paid(1)	(1,623)	(1,248)	(890)	(912)	(96)	(224)
	Other	-	-	(112)	(245)	-	-
Fair value at December 31		10,985	12,915	18,417	20,095	414	468

(1) Benefit payments for funded plans.

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, certain 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 encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.

		Pension Benefits
		U.S.		Non-U.S.
		2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(5,782)	(4,590)	(588)	(2,113)
	Unfunded plans	(2,816)	(3,024)	(6,112)	(7,839)
Total		(8,598)	(7,614)	(6,700)	(9,952)

The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status 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 the year in which the changes occur through other comprehensive income.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31 (1)	(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	-	454	302	-	-
	Current liabilities	(311)	(340)	(299)	(325)	(363)	(369)
	Postretirement benefits reserves	(8,287)	(7,274)	(6,855)	(9,929)	(7,505)	(8,599)
Total recorded		(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,138	6,589	6,413	9,642	2,171	2,997
	Prior service cost	21	27	(83)	429	(460)	51
Total recorded in accumulated other
	comprehensive income	6,159	6,616	6,330	10,071	1,711	3,048

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

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 return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.

									Other
			Pension Benefits						Postretirement
			U.S.			Non-U.S.			Benefits
			2015	2014	2013	2015	2014	2013	2015	2014	2013
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31	(percent)
	Discount rate		4.00	5.00	4.00	3.10	4.30	3.80	4.00	5.00	4.00
	Long-term rate of return on funded assets		7.00	7.25	7.25	5.90	6.30	6.40	7.00	7.25	7.25
	Long-term rate of compensation increase		5.75	5.75	5.75	5.30	5.40	5.50	5.75	5.75	5.75
Components of net periodic benefit cost			(millions of dollars)
	Service cost		864	677	801	689	590	697	170	140	176
	Interest cost		785	807	749	850	1,138	1,076	346	383	352
	Expected return on plan assets		(830)	(799)	(835)	(1,094)	(1,193)	(1,128)	(28)	(37)	(41)
	Amortization of actuarial loss/(gain)		544	409	646	730	628	852	206	116	228
	Amortization of prior service cost		6	8	7	87	120	117	(24)	14	21
	Net pension enhancement and
	curtailment/settlement cost		499	276	723	22	-	22	-	-	-
Net periodic benefit cost			1,868	1,378	2,091	1,284	1,283	1,636	670	616	736
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)		592	2,494	(1,302)	(1,375)	2,969	(1,938)	(589)	1,518	(1,290)
	Amortization of actuarial (loss)/gain		(1,043)	(685)	(1,369)	(752)	(628)	(874)	(206)	(116)	(228)
	Prior service cost/(credit)		-	(25)	-	(401)	(70)	30	(535)	-	-
	Amortization of prior service (cost)/credit		(6)	(8)	(7)	(87)	(120)	(117)	24	(14)	(21)
	Foreign exchange rate changes		-	-	-	(1,126)	(688)	(155)	(31)	(8)	(10)
Total recorded in other comprehensive income			(457)	1,776	(2,678)	(3,741)	1,463	(3,054)	(1,337)	1,380	(1,549)
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax		1,411	3,154	(587)	(2,457)	2,746	(1,418)	(667)	1,996	(813)

Costs for defined contribution plans were $405million, $393 million and $392 million in 2015, 2014 and 2013, respectively.

A summary of the change in accumulated other comprehensive income is shown in the table below:

		Total Pension and
		Other Postretirement Benefits
		2015	2014	2013
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	457	(1,776)	2,678
	Non-U.S. pension	3,741	(1,463)	3,054
	Other postretirement benefits	1,337	(1,380)	1,549
Total (charge)/credit to other comprehensive income, before tax		5,535	(4,619)	7,281
(Charge)/credit to income tax (see Note 4)		(1,810)	1,549	(2,336)
(Charge)/credit to investment in equity companies		81	(81)	49
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	3,806	(3,151)	4,994
Charge/(credit) to equity of noncontrolling interests		(202)	85	(279)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		3,604	(3,066)	4,715

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed 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 and the major non-U.S. plans is 40 percent equity securities and60 percent debt securities. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on 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 risk or credit quality of an investment.

The 2015 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, 2015, Using:							at December 31, 2015, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	1,992	(1)	-		1,992		-		3,179	(1)	-		3,179
		Non-U.S.		-	1,775	(1)	-		1,775		179	(2)	3,429	(1)	-		3,608
	Private equity			-	-		595	(3)	595		-		-		581	(3)	581
	Debt securities
		Corporate		-	4,161	(4)	-		4,161		-		2,561	(4)	-		2,561
		Government		-	2,394	(4)	-		2,394		243	(5)	8,125	(4)	-		8,368
		Asset-backed		-	3	(4)	-		3		-		71	(4)	-		71
	Real estate funds			-	-		-		-		-		-		-		-
	Cash			-	50	(6)	-		50		11		12	(7)	-		23
Total at fair value				-	10,375		595		10,970		433		17,377		581		18,391
	Insurance contracts
		at contract value							15								26
Total plan assets									10,985								18,417

(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 Level 2 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 Public 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 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 input.

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

			Other Postretirement
				Fair Value Measurement
			at December 31, 2015, Using:
				Level 1	Level 2		Level 3	Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	96	(1)	-	96
		Non-U.S.		-	67	(1)	-	67
	Private equity			-	-		-	-
	Debt securities
		Corporate		-	79	(2)	-	79
		Government		-	170	(2)	-	170
		Asset-backed		-	1	(2)	-	1
	Cash			-	1		-	1
Total at fair value				-	414		-	414

(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 Level 2 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 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 2015 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2015
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	562	535	57	2
Net realized gains/(losses)	1	26	(5)	-
Net unrealized gains/(losses)	106	64	-	-
Net purchases/(sales)	(74)	(44)	(52)	(2)
Fair value at December 31	595	581	-	-

The 2014 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, 2014, Using:							at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	2,331	(1)	-		2,331		-		3,284	(1)	-		3,284
		Non-U.S.		-	2,144	(1)	-		2,144		229	(2)	3,776	(1)	-		4,005
	Private equity			-	-		562	(3)	562		-		-		535	(3)	535
	Debt securities
		Corporate		-	4,841	(4)	-		4,841		-		2,686	(4)	-		2,686
		Government		-	2,890	(4)	-		2,890		249	(5)	9,050	(4)	-		9,299
		Asset-backed		-	5	(4)	-		5		-		146	(4)	-		146
	Real estate funds			-	-		-		-		-		-		57	(6)	57
	Cash			-	131	(7)	-		131		25		31	(8)	-		56
Total at fair value				-	12,342		562		12,904		503		18,973		592		20,068
	Insurance contracts
		at contract value							11								27
Total plan assets									12,915								20,095

(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 Level 2 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 Public 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 input.

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

			Other Postretirement
			Fair Value Measurement
			at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	106	(1)	-		106
		Non-U.S.		-	75	(1)	-		75
	Private equity			-	-		2	(2)	2
	Debt securities
		Corporate		-	103	(3)	-		103
		Government		-	171	(3)	-		171
		Asset-backed		-	9	(3)	-		9
	Cash			-	2		-		2
Total at fair value				-	466		2		468

(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 Level 2 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 Public 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 2014 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2014
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	523	502	136	9
Net realized gains/(losses)	2	23	(17)	-
Net unrealized gains/(losses)	89	31	8	-
Net purchases/(sales)	(52)	(21)	(70)	(7)
Fair value at December 31	562	535	57	2

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.
			2015	2014		2015	2014
		(millions of dollars)
For funded pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		16,767	17,505		1,827	5,031
	Accumulated benefit obligation		13,913	14,493		1,373	4,590
	Fair value of plan assets		10,985	12,915		1,299	3,890
For unfunded pension plans:
	Projected benefit obligation		2,816	3,024		6,112	7,839
	Accumulated benefit obligation		1,753	1,892		5,290	6,573

					Other
			Pension Benefits		Postretirement
			U.S.	Non-U.S.	Benefits
		(millions of dollars)
Estimated 2016 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain) (1)		930	543		152
	Prior service cost (2)		6	55		(30)

(1) The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service 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 other postretirement benefit plans.

		Pension Benefits		Other Postretirement Benefits
					Medicare
		U.S.	Non-U.S.	Gross	Subsidy Receipt
		(millions of dollars)
Contributions expected in 2016		2,000	525	-		-
Benefit payments expected in:
	2016	1,548	1,145	457		24
	2017	1,491	1,128	470		25
	2018	1,411	1,178	481		26
	2019	1,382	1,193	490		28
	2020	1,342	1,227	497		29
	2021 - 2025	6,594	6,359	2,518		170

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Disclosures About Segments And Related Information

12 Months Ended

Dec. 31, 2015

Disclosures About Segments And Related Information [Abstract]

Disclosures About Segments And Related Information

18. Disclosures about Segments and Related Information

The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.

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

Earnings after income tax include transfers at estimated market prices.

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities.Interest expense includes non-debt-related interest expense of $100 million and $129 million in 2015 and 2014, respectively. For 2013, non-debt-related interest expense was a net credit of $123 million, primarily reflecting the effect of credits from the favorable resolution of prior year tax positions.

													Corporate
	Upstream				Downstream				Chemical					and	Corporate
	U.S.		Non-U.S.		U.S.		Non-U.S.		U.S.		Non-U.S.		Financing			Total
		(millions of dollars)
As of December 31, 2015
Earnings after income tax		(1,079)		8,180		1,901		4,656		2,386		2,032		(1,926)		16,150
Earnings of equity companies included above		226		5,831		170		444		144		1,235		(406)		7,644
Sales and other operating revenue (1)		8,241		15,812		73,063		134,230		10,880		17,254		8		259,488
Intersegment revenue		4,344		20,839		12,440		22,166		7,442		5,168		274		-
Depreciation and depletion expense		5,301		9,227		664		1,003		375		654		824		18,048
Interest revenue		-		-		-		-		-		-		46		46
Interest expense		26		27		8		4		-		1		245		311
Income taxes		(879)		4,703		866		1,325		646		633		(1,879)		5,415
Additions to property, plant and equipment		6,915		14,561		916		1,477		1,865		629		1,112		27,475
Investments in equity companies		5,160		10,980		95		1,179		125		3,025		(227)		20,337
Total assets		93,648		155,316		16,498		29,808		10,174		18,236		13,078		336,758
As of December 31, 2014
Earnings after income tax		5,197		22,351		1,618		1,427		2,804		1,511		(2,388)		32,520
Earnings of equity companies included above		1,235		10,859		29		82		186		1,377		(445)		13,323
Sales and other operating revenue (1)		14,826		22,336		118,771		199,976		15,115		23,063		18		394,105
Intersegment revenue		7,723		38,846		17,281		44,231		10,117		8,098		274		-
Depreciation and depletion expense		5,139		8,523		654		1,228		370		645		738		17,297
Interest revenue		-		-		-		-		-		-		75		75
Interest expense		40		17		6		4		-		-		219		286
Income taxes		1,300		15,165		610		968		1,032		358		(1,418)		18,015
Additions to property, plant and equipment		9,098		19,225		1,050		1,356		1,564		564		1,399		34,256
Investments in equity companies		5,089		10,877		69		1,006		258		3,026		(308)		20,017
Total assets		92,555		161,033		18,371		33,299		8,798		18,449		16,988		349,493
As of December 31, 2013
Earnings after income tax		4,191		22,650		2,199		1,250		2,755		1,073		(1,538)		32,580
Earnings of equity companies included above		1,576		11,627		(460)		22		189		1,422		(449)		13,927
Sales and other operating revenue (1)		13,712		25,349		123,802		218,904		15,295		23,753		21		420,836
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		17,182
Interest revenue		-		-		-		-		-		-		87		87
Interest expense		30		26		7		8		1		-		(63)		9
Income taxes		2,197		21,554		721		481		989		363		(2,042)		24,263
Additions to property, plant and equipment		7,480		26,075		616		1,072		840		272		1,386		37,741
Investments in equity companies		4,975		9,740		62		1,749		217		3,103		(227)		19,619
Total assets		88,698		157,465		19,261		40,661		7,816		19,659		13,248		346,808

(1) Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015,$29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

Geographic
Sales and other operating revenue (1)		2015	2014	2013
		(millions of dollars)
United States		92,184	148,713	152,820
Non-U.S.		167,304	245,392	268,016
	Total	259,488	394,105	420,836
Significant non-U.S. revenue sources include:
	United Kingdom	23,651	31,346	34,061
	Canada	22,876	36,072	35,924
	Italy	13,795	18,880	19,273
	Belgium	13,154	20,953	20,973
	France	11,808	17,639	18,444
	Singapore	10,790	15,407	15,623
	Germany	10,045	14,816	15,701

(1) Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

Long-lived assets		2015	2014	2013
		(millions of dollars)
United States		107,039	104,000	98,271
Non-U.S.		144,566	148,668	145,379
	Total	251,605	252,668	243,650
Significant non-U.S. long-lived assets include:
	Canada	39,775	43,858	41,522
	Australia	15,894	15,328	14,258
	Nigeria	12,222	12,265	12,343
	Kazakhstan	9,705	9,138	8,530
	Singapore	9,681	9,620	9,570
	Angola	8,777	9,057	8,262
	Papua New Guinea	5,985	6,099	5,768

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Income, Sales-Based And Other Taxes

12 Months Ended

Dec. 31, 2015

Income, Sales-Based And Other Taxes [Abstract]

Income, Sales-Based And Other Taxes

19. Income, Sales-Based and Other Taxes

						2015				2014				2013
				U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total
								(millions of dollars)
Income tax expense
	Federal and non-U.S.
		Current		-		7,126	7,126	1,456		14,755	16,211	1,073		22,115	23,188
		Deferred - net		(1,166)		(571)	(1,737)	900		1,398	2,298	(116)		757	641
	U.S. tax on non-U.S. operations			38		-	38	5		-	5	37		-	37
			Total federal and non-U.S.	(1,128)		6,555	5,427	2,361		16,153	18,514	994		22,872	23,866
	State (1)			(12)		-	(12)	(499)		-	(499)	397		-	397
			Total income tax expense	(1,140)		6,555	5,415	1,862		16,153	18,015	1,391		22,872	24,263
Sales-based taxes				6,402		16,276	22,678	6,310		23,032	29,342	5,992		24,597	30,589
All other taxes and duties
	Other taxes and duties			162		27,103	27,265	378		31,908	32,286	955		32,275	33,230
	Included in production and
		manufacturing expenses		1,157		828	1,985	1,454		1,179	2,633	1,318		1,182	2,500
	Included in SG&A expenses			150		390	540	155		441	596	150		516	666
		Total other taxes and duties		1,469		28,321	29,790	1,987		33,528	35,515	2,423		33,973	36,396
			Total	6,731		51,152	57,883	10,159		72,713	82,872	9,806		81,442	91,248

(1)In 2014, state taxes included a favorable adjustment of deferred taxes of approximately $830 million.

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include a net charge of $177 million in 2015 and net credits of $40 million in 2014 and $310 million in 2013 for the 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 for2015, 2014 and2013 is as follows:

			2015	2014	2013
			(millions of dollars)
Income before income taxes
	United States		147	9,080	9,746
	Non-U.S.		21,819	42,550	47,965
		Total	21,966	51,630	57,711
Theoretical tax			7,688	18,071	20,199
Effect of equity method of accounting			(2,675)	(4,663)	(4,874)
Non-U.S. taxes in excess of theoretical U.S. tax			1,415	5,442	10,528
U.S. tax on non-U.S. operations			38	5	37
State taxes, net of federal tax benefit			(8)	(324)	258
Other			(1,043)	(516)	(1,885)
		Total income tax expense	5,415	18,015	24,263
Effective tax rate calculation
Income taxes			5,415	18,015	24,263
ExxonMobil share of equity company income taxes			3,011	5,678	6,061
		Total income taxes	8,426	23,693	30,324
Net income including noncontrolling interests			16,551	33,615	33,448
		Total income before taxes	24,977	57,308	63,772
Effective income tax rate			34%	41%	48%

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

Deferred tax liabilities/(assets) are comprised of the following at December 31:

Tax effects of temporary differences for:		2015	2014
		(millions of dollars)
Property, plant and equipment		49,409	51,643
Other liabilities		4,613	4,359
	Total deferred tax liabilities	54,022	56,002
Pension and other postretirement benefits		(6,286)	(8,140)
Asset retirement obligations		(6,277)	(6,162)
Tax loss carryforwards		(4,983)	(4,099)
Other assets		(5,592)	(6,446)
	Total deferred tax assets	(23,138)	(24,847)
Asset valuation allowances		1,730	2,570
	Net deferred tax liabilities	32,614	33,725

In 2015, asset valuation allowances of $1,730 million decreased by $840 million and included net provisions of $681 million and effects of foreign currency translation of $159 million.

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

Balance sheet classification		2015	2014
		(millions of dollars)
Other current assets		(1,329)	(2,001)
Other assets, including intangibles, net		(3,421)	(3,955)
Accounts payable and accrued liabilities		546	451
Deferred income tax liabilities		36,818	39,230
	Net deferred tax liabilities	32,614	33,725

The Corporation had $51 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. thatwere retained to fund prior and future capital project expenditures. Deferred taxes have not been recorded for potential future tax obligations as these earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2015, it is not practical to estimate the unrecognized deferred tax liability associated with these earnings given thefuture availability of foreign tax credits and uncertainties about the timing of potential remittances

UnrecognizedTaxBenefits. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits:

Gross unrecognized tax benefits		2015	2014	2013
		(millions of dollars)
Balance at January 1		8,986	7,838	7,663
	Additions based on current year's tax positions	903	1,454	1,460
	Additions for prior years' tax positions	496	448	464
	Reductions for prior years' tax positions	(190)	(532)	(249)
	Reductions due to lapse of the statute of limitations	(4)	(117)	(588)
	Settlements with tax authorities	(725)	(43)	(849)
	Foreign exchange effects/other	(70)	(62)	(63)
Balance at December 31		9,396	8,986	7,838

The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2015, 2014 and 2013 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income.

Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation.In the United States, the Corporation has various U.S. federal income tax positions at issue with the Internal Revenue Service for tax years 2006-2011. Unfavorable resolution of these issues would not have a materially adverse effect on the Corporation’s net income or liquidity. The Internal Revenue Service has not completed its audit of tax years after 2011.

It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent in the next 12 months, with no material impact on the Corporation’s net income.

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

Country of Operation	Open Tax Years
Abu Dhabi	2012 - 2015
Angola	2009 - 2015
Australia	2005, 2008 - 2015
Canada	2008 - 2015
Equatorial Guinea	2007 - 2015
Malaysia	2009 - 2015
Nigeria	2005 - 2015
Norway	2007 - 2015
Qatar	2009 - 2015
Russia	2012 - 2015
United Kingdom	2011 - 2015
United States	2006 - 2015

The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.

The Corporation incurred $39 million and $42 million in interest expense on income tax reserves in 2015 and 2014, respectively. 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 year tax positions. The related interest payable balances were $223 million and $205 million at December 31, 2015, and 2014, respectively.

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Summary Of Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2015

Summary Of Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the 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 included in “Investments, advances and long-term receivables.” The Corporation’s share of the net income of these companies is included in the Consolidated Statement 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 indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in Accumulated Other 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 if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

Revenue Recognition

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

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

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

Sales-Based Taxes

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

Derivative Instruments

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

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives 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 underlying hedged item.

Fair Value

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 participants. 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 prices in active markets for identical assets or liabilities. Hierarchy Level2 inputs are inputs other than quoted prices included within Level1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

Inventories

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

Property, Plant And Equipment

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

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized.

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-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using 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 transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used.

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

The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for this assessment.

Potential trigger events for impairment evaluation include:

• a significant decrease in the market price of a long-lived asset;
• a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;
• a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;
• an accumulation of project costs significantly in excess of the amount originally expected;
• a current-period operating loss combined with a history and forecast of operating or cash flow losses; and
• a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

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

If there were a trigger event, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

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

Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any 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 carrying value.

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

Asset Retirement Obligations And Environmental Liabilities

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. 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 estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.

Foreign Currency Translation

Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the 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 inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.

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

Stock-Based Payments

Stock-Based Payments. The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock units. 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.

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Miscellaneous Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Miscellaneous Financial Information [Abstract]

Crude Oil, Products And Merchandise

		2015	2014
		(billions of dollars)
Crude oil		4.2	4.6
Petroleum products		4.1	4.1
Chemical products		2.7	2.9
Gas/other		1.0	0.8
	Total	12.0	12.4

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Other Comprehensive Income Information (Tables)

12 Months Ended

Dec. 31, 2015

Other Comprehensive Income Information [Abstract]

Schedule Of Accumulated Other Comprehensive Income Information

		Cumulative	Post-
		Foreign	retirement	Unrealized
		Exchange	Benefits	Change in
ExxonMobil Share of Accumulated Other		Translation	Reserves	Stock
Comprehensive Income		Adjustment	Adjustment	Investments	Total
		(millions of dollars)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(3,233)	2,963	-	(270)
Amounts reclassified from accumulated other
	comprehensive income	(23)	1,752	-	1,729
Total change in accumulated other comprehensive income		(3,256)	4,715	-	1,459
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Balance as of December 31, 2013		(846)	(9,879)	-	(10,725)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(5,258)	(4,132)	(63)	(9,453)
Amounts reclassified from accumulated other
	comprehensive income	152	1,066	3	1,221
Total change in accumulated other comprehensive income		(5,106)	(3,066)	(60)	(8,232)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Balance as of December 31, 2014		(5,952)	(12,945)	(60)	(18,957)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	(8,204)	2,202	33	(5,969)
Amounts reclassified from accumulated other
	comprehensive income	(14)	1,402	27	1,415
Total change in accumulated other comprehensive income		(8,218)	3,604	60	(4,554)
Balance as of December 31, 2015		(14,170)	(9,341)	-	(23,511)

Reclassification Out Of Accumulated Other Comprehensive Income

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2015	2014	2013
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	14	(152)	23
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(2,066)	(1,571)	(2,616)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(42)	(5)	-

(1)These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 17 – Pension and Other Postretirement Benefits for additional details.)

Schedule Of Income Tax (Expense)/Credit For Components Of Other Comprehensive Income

Income Tax (Expense)/Credit For
Components of Other Comprehensive Income		2015	2014	2013
		(millions of dollars)
Foreign exchange translation adjustment		170	292	218
Postretirement benefits reserves adjustment (excluding amortization)		(1,192)	2,009	(1,540)
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(618)	(460)	(796)
Unrealized change in fair value of stock investments		(17)	34	-
Realized change in fair value of stock investments included in net income		(15)	(2)	-
Total		(1,672)	1,873	(2,118)

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Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Cash Flow Information [Abstract]

Cash payments for interest and income taxes

	2015	2014	2013
	(millions of dollars)
Cash payments for interest	586	380	426
Cash payments for income taxes	7,269	18,085	25,066

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Additional Working Capital Information (Tables)

12 Months Ended

Dec. 31, 2015

Additional Working Capital Information [Abstract]

Schedule Of Notes, Accounts Receivable And Payable, Loans Payable, And Accrued Liabilities

			Dec. 31	Dec. 31
			2015	2014
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $107 million and $113 million		13,243	18,541
	Other, less reserves of $4 million and $48 million		6,632	9,468
		Total	19,875	28,009
Notes and loans payable
	Bank loans		231	473
	Commercial paper		17,973	16,225
	Long-term debt due within one year		558	770
		Total	18,762	17,468
Accounts payable and accrued liabilities
	Trade payables		18,074	25,286
	Payables to equity companies		4,639	6,589
	Accrued taxes other than income taxes		2,937	3,290
	Other		6,762	7,062
		Total	32,412	42,227

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Equity Company Information (Tables)

12 Months Ended

Dec. 31, 2015

Equity Company Information [Abstract]

Schedule Of Equity Company Financial Summary

		2015			2014			2013
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		111,866		34,297	183,708		55,855	236,161		68,084
Income before income taxes		36,379		10,670	65,549		19,014	69,454		19,999
Income taxes		11,048		3,019	20,520		5,684	21,618		6,069
	Income from equity affiliates	25,331		7,651	45,029		13,330	47,836		13,930
Current assets		32,879		11,244	49,905		16,802	62,398		19,545
Long-term assets		109,684		32,878	110,754		33,619	116,450		35,695
	Total assets	142,563		44,122	160,659		50,421	178,848		55,240
Current liabilities		22,947		6,738	37,333		11,472	54,550		15,243
Long-term liabilities		60,388		17,165	66,231		19,470	68,857		20,873
	Net assets	59,228		20,219	57,095		19,479	55,441		19,124

Schedule Of The Corporation's Percentage Ownership Interest

	Percentage
	Ownership
	Interest
Upstream
Aera Energy LLC	48
BEB Erdgas und Erdoel GmbH & Co. KG	50
Cameroon Oil Transportation Company S.A.	41
Cross Timbers Energy, LLC	50
Golden Pass LNG Terminal LLC	18
Karmorneftegaz Holding SARL	33
Marine Well Containment Company LLC	10
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
Downstream
Fujian Refining & Petrochemical Co. Ltd.	25
Saudi Aramco Mobil Refinery Company Ltd.	50
Chemical
Al-Jubail Petrochemical Company	50
Infineum Holdings B.V.	50
Infineum Italia s.r.l.	50
Infineum USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

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Investments, Advances And Long-Term Receivables (Tables)

12 Months Ended

Dec. 31, 2015

Investments, Advances And Long-Term Receivables [Abstract]

Schedule Of Investments, Advances And Long-Term Receivables

			Dec. 31,	Dec. 31,
			2015	2014
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,337	20,017
	Advances		9,110	9,818
		Total equity company investments and advances	29,447	29,835
Companies carried at cost or less and stock investments carried at fair value			274	526
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $3,040 million and $2,662 million		4,524	4,878
		Total	34,245	35,239

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Property, Plant And Equipment And Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant And Equipment And Asset Retirement Obligations [Abstract]

Property, Plant And Equipment

		December 31, 2015		December 31, 2014
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,821	203,822	347,170	205,308
Downstream		50,742	21,330	53,327	22,639
Chemical		32,481	16,247	30,717	14,918
Other		16,293	10,206	15,575	9,803
	Total	447,337	251,605	446,789	252,668

Asset Retirement Obligations

		2015	2014
		(millions of dollars)
Beginning balance		13,424	12,988
	Accretion expense and other provisions	775	871
	Reduction due to property sales	(208)	(151)
	Payments made	(928)	(724)
	Liabilities incurred	283	122
	Foreign currency translation	(931)	(908)
	Revisions	1,289	1,226
Ending balance		13,704	13,424

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Accounting For Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2015

Accounting For Suspended Exploratory Well Costs [Abstract]

Change In Capitalized Suspended Exploratory Well Costs

			2015	2014	2013
			(millions of dollars)
Balance beginning at January 1			3,587	2,707	2,679
	Additions pending the determination of proved reserves		847	1,095	293
	Charged to expense		(5)	(28)	(52)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(43)	(160)	(107)
	Divestments/Other		(14)	(27)	(106)
Ending balance at December 31			4,372	3,587	2,707
Ending balance attributed to equity companies included above			696	645	13

Period End Capitalized Suspended Exploratory Well Costs

			2015	2014	2013
			(millions of dollars)
Capitalized for a period of one year or less			847	1,095	293
	Capitalized for a period of between one and five years		2,386	1,659	1,705
	Capitalized for a period of between five and ten years		826	544	470
	Capitalized for a period of greater than ten years		313	289	239
Capitalized for a period greater than one year - subtotal			3,525	2,492	2,414
		Total	4,372	3,587	2,707

Number Of Projects With Suspended Exploratory Well Costs

			2015	2014	2013
Number of projects with first capitalized well drilled in the preceding 12 months			4	8	8
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		55	53	50
		Total	59	61	58

Additional Detail For Projects With Completed Exploratory Activity Progressing Toward Development

			Years
		Dec. 31,	Wells
Country/Project		2015	Drilled	Comment
	(millions of dollars)
Angola
- Kaombo Split Hub Phase 2		20	2005 - 2006	Evaluating development plan to tie into planned production facilities.
- Perpetua-Zinia-Acacia		15	2008 - 2009	Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure.
Australia
- East Pilchard		7	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		11	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		34	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Canada
- Horn River		241	2009 - 2012	Evaluating development alternatives to tie into planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		29	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.
- Kalamkas		18	2006 - 2009	Evaluating development alternatives, while continuing discussions with the
				government regarding development plan.
Malaysia
- 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.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Pegi		32	2009	Awaiting capacity in existing/planned infrastructure.
- Satellite Field		12	2013	Evaluating development plan to tie into planned production facilities.
Development Phase 2
- Other (4 projects)		14	2002	Evaluating and pursuing development of several additional discoveries.
Norway
- Gamma		13	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		15	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		25	2008 - 2014	Evaluating development plans, including potential for tieback to existing production
				facilities.
Papua New Guinea
- Juha		28	2007	Progressing development plans to tie into existing 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
- Hadrian North		209	2010 - 2013	Evaluating development plan to tie into existing production facilities.
- Tip Top		31	2009	Evaluating development concept and requisite facility upgrades.
Total 2015 (37 projects)		1,154

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Leased Facilities (Tables)

12 Months Ended

Dec. 31, 2015

Leased Facilities [Abstract]

Leased Facilities

	Lease Payments Under Minimum Commitments			Related
	Drilling Rigs			Sublease
	and Related			Rental
	Equipment	Other	Total	Income
	(millions of dollars)
2016	827	826	1,653	7
2017	408	595	1,003	6
2018	134	421	555	2
2019	89	255	344	2
2020	77	188	265	2
2021 and beyond	86	971	1,057	13
Total	1,621	3,256	4,877	32

Net Rental Cost

			2015	2014	2013
			(millions of dollars)
Rental cost
	Drilling rigs and related equipment		1,853	1,763	1,424
	Other		2,120	2,314	2,417
		Total	3,973	4,077	3,841
	Less sublease rental income		44	52	44
Net rental cost			3,929	4,025	3,797

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share Computation

	2015	2014	2013
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	16,150	32,520	32,580
Weighted average number of common shares outstanding(millions of shares)	4,196	4,282	4,419
Earnings per common share(dollars) (1)	3.85	7.60	7.37
Dividends paid per common share (dollars)	2.88	2.70	2.46

(1)The earnings per common share and earnings per common share - assuming dilution are the same in each period shown.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Long-Term Debt [Abstract]

Summarized Long-Term Debt

			2015	2014
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	1,500
	Floating-rate notes due 2017 (1)		750	750
	Floating-rate notes due 2018 (2)		500	-
	1.305% notes due 2018		1,600	-
	1.819% notes due 2019		1,750	1,750
	Floating-rate notes due 2019 (3)		500	500
	1.912% notes due 2020		1,500	-
	2.397% notes due 2022		1,150	-
	Floating-rate notes due 2022 (4)		500	-
	3.176% notes due 2024		1,000	1,000
	2.709% notes due 2025		1,750	-
	3.567% notes due 2045		1,000	-
XTO Energy Inc. (5)
	5.650% senior notes due 2016		-	207
	6.250% senior notes due 2017		465	477
	5.500% senior notes due 2018		377	383
	6.500% senior notes due 2018		463	474
	6.100% senior notes due 2036		198	199
	6.750% senior notes due 2037		307	309
	6.375% senior notes due 2038		235	236
Mobil Producing Nigeria Unlimited (6)
	Variable notes due 2016-2019		101	399
Esso (Thailand) Public Company Ltd.(7)
	Variable notes due 2016-2020		83	121
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2017-2051 (8)			2,611	2,611
Other U.S. dollar obligations (9)			97	104
Other foreign currency obligations			1	9
Capitalized lease obligations(10)			1,238	375
		Total long-term debt	19,925	11,653

(1)Average effective interest rate of 0.3% in 2015 and 0.3% in 2014.

(2)Average effective interest rate of 0.4% in 2015.

(3) Average effective interest rate of 0.5% in 2015 and 0.4% in 2014.

(4) Average effective interest rate of 0.7% in 2015.

(5)Includes premiums of $179 millionin 2015 and $219 million in 2014.

(6)Average effective interest rate of 4.6% in 2015 and 4.5% in 2014.

(7)Average effective interest rate of 2.1% in 2015 and 2.4% in 2014.

(8)Average effective interest rate of 0.02% in 2015 and 0.03% in 2014.

(9)Average effective interest rate of 3.8% in 2015 and 4.2% in 2014.

(10)Average imputed interest rate of 9.2% in 2015 and 7.0% in 2014.

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Incentive Program (Tables)

12 Months Ended

Dec. 31, 2015

Incentive Program [Abstract]

Summary Of Restricted Stock And Units Outstanding

	2015
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	44,439		81.45
2014 award issued in 2015	9,758		95.20
Vested	(9,945)		79.86
Forfeited	(189)		82.26
Issued and outstanding at December 31	44,063		84.85

Grant Value Of Restricted Stock And Units

Value of restricted stock and units	2015	2014	2013
Grant price (dollars)	81.27	95.20	94.47
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	727	858	843
Units settled in cash	60	73	76
Total value	787	931	919

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Litigation And Other Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Litigation And Other Contingencies [Abstract]

Schedule Of Guarantees

						Dec. 31, 2015
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			98		35	133
	Other			2,539		4,553	7,092
		Total		2,637		4,588	7,225
(1) ExxonMobil share.

Unconditional Purchase Obligations

	Payments Due by Period
		2017-	2021 and
	2016	2020	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	133	493		310	936

(1) Undiscounted obligations of $936million mainly pertain to pipeline throughput agreements and include $411million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $144million, totaled $792million.

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Pension And Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

Pension And Other Postretirement Benefits [Abstract]

Change In Benefit Obligation Of Pension And Other Postretirement Benefits

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.25	4.00	3.60	3.10	4.25	4.00
	Long-term rate of compensation increase	5.75	5.75	4.80	5.30	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	20,529	17,304	30,047	27,357	9,436	7,868
	Service cost	864	677	689	590	170	140
	Interest cost	785	807	850	1,138	346	383
	Actuarial loss/(gain)	(545)	3,192	(1,517)	4,929	(617)	1,522
	Benefits paid (1) (2)	(2,050)	(1,427)	(1,287)	(1,366)	(482)	(525)
	Foreign exchange rate changes	-	-	(3,242)	(2,540)	(106)	(48)
	Amendments, divestments and other	-	(24)	(423)	(61)	(465)	96
Benefit obligation at December 31		19,583	20,529	25,117	30,047	8,282	9,436
Accumulated benefit obligation at December 31		15,666	16,385	22,362	26,318	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2015 and 2014, other postretirement benefits paid are net of $15 million and $21 million of Medicare subsidy receipts, respectively.

Change In Plan Assets Of Pension And Other Postretirement Benefits

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Change in plan assets
	Fair value at January 1	12,915	11,190	20,095	19,283	468	620
	Actual return on plan assets	(307)	1,497	918	3,153	-	41
	Foreign exchange rate changes	-	-	(2,109)	(1,738)	-	-
	Company contribution	-	1,476	515	554	42	31
	Benefits paid(1)	(1,623)	(1,248)	(890)	(912)	(96)	(224)
	Other	-	-	(112)	(245)	-	-
Fair value at December 31		10,985	12,915	18,417	20,095	414	468

(1) Benefit payments for funded plans.

Summary Of Assets In Excess Of/(Less Than) Benefit Obligation

		Pension Benefits
		U.S.		Non-U.S.
		2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(5,782)	(4,590)	(588)	(2,113)
	Unfunded plans	(2,816)	(3,024)	(6,112)	(7,839)
Total		(8,598)	(7,614)	(6,700)	(9,952)

Amounts Recorded In Balance Sheet And Other Comprehensive Income

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2015	2014	2015	2014	2015	2014
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31 (1)	(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	-	454	302	-	-
	Current liabilities	(311)	(340)	(299)	(325)	(363)	(369)
	Postretirement benefits reserves	(8,287)	(7,274)	(6,855)	(9,929)	(7,505)	(8,599)
Total recorded		(8,598)	(7,614)	(6,700)	(9,952)	(7,868)	(8,968)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,138	6,589	6,413	9,642	2,171	2,997
	Prior service cost	21	27	(83)	429	(460)	51
Total recorded in accumulated other
	comprehensive income	6,159	6,616	6,330	10,071	1,711	3,048

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

Schedule Of Assumptions, Components Of Benefit Cost And Amounts Recorded In Accumulated Other Comprehensive Income For Pension And Other Postretirement Benefits

									Other
			Pension Benefits						Postretirement
			U.S.			Non-U.S.			Benefits
			2015	2014	2013	2015	2014	2013	2015	2014	2013
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31	(percent)
	Discount rate		4.00	5.00	4.00	3.10	4.30	3.80	4.00	5.00	4.00
	Long-term rate of return on funded assets		7.00	7.25	7.25	5.90	6.30	6.40	7.00	7.25	7.25
	Long-term rate of compensation increase		5.75	5.75	5.75	5.30	5.40	5.50	5.75	5.75	5.75
Components of net periodic benefit cost			(millions of dollars)
	Service cost		864	677	801	689	590	697	170	140	176
	Interest cost		785	807	749	850	1,138	1,076	346	383	352
	Expected return on plan assets		(830)	(799)	(835)	(1,094)	(1,193)	(1,128)	(28)	(37)	(41)
	Amortization of actuarial loss/(gain)		544	409	646	730	628	852	206	116	228
	Amortization of prior service cost		6	8	7	87	120	117	(24)	14	21
	Net pension enhancement and
	curtailment/settlement cost		499	276	723	22	-	22	-	-	-
Net periodic benefit cost			1,868	1,378	2,091	1,284	1,283	1,636	670	616	736
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)		592	2,494	(1,302)	(1,375)	2,969	(1,938)	(589)	1,518	(1,290)
	Amortization of actuarial (loss)/gain		(1,043)	(685)	(1,369)	(752)	(628)	(874)	(206)	(116)	(228)
	Prior service cost/(credit)		-	(25)	-	(401)	(70)	30	(535)	-	-
	Amortization of prior service (cost)/credit		(6)	(8)	(7)	(87)	(120)	(117)	24	(14)	(21)
	Foreign exchange rate changes		-	-	-	(1,126)	(688)	(155)	(31)	(8)	(10)
Total recorded in other comprehensive income			(457)	1,776	(2,678)	(3,741)	1,463	(3,054)	(1,337)	1,380	(1,549)
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax		1,411	3,154	(587)	(2,457)	2,746	(1,418)	(667)	1,996	(813)

Summary Of Change In Accumulated Other Comprehensive Income

		Total Pension and
		Other Postretirement Benefits
		2015	2014	2013
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	457	(1,776)	2,678
	Non-U.S. pension	3,741	(1,463)	3,054
	Other postretirement benefits	1,337	(1,380)	1,549
Total (charge)/credit to other comprehensive income, before tax		5,535	(4,619)	7,281
(Charge)/credit to income tax (see Note 4)		(1,810)	1,549	(2,336)
(Charge)/credit to investment in equity companies		81	(81)	49
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	3,806	(3,151)	4,994
Charge/(credit) to equity of noncontrolling interests		(202)	85	(279)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		3,604	(3,066)	4,715

Fair Value Of The Benefit Plan Assets (Pension)

			U.S. Pension							Non-U.S. Pension
			Fair Value Measurement							Fair Value Measurement
			at December 31, 2015, Using:							at December 31, 2015, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	1,992	(1)	-		1,992		-		3,179	(1)	-		3,179
		Non-U.S.		-	1,775	(1)	-		1,775		179	(2)	3,429	(1)	-		3,608
	Private equity			-	-		595	(3)	595		-		-		581	(3)	581
	Debt securities
		Corporate		-	4,161	(4)	-		4,161		-		2,561	(4)	-		2,561
		Government		-	2,394	(4)	-		2,394		243	(5)	8,125	(4)	-		8,368
		Asset-backed		-	3	(4)	-		3		-		71	(4)	-		71
	Real estate funds			-	-		-		-		-		-		-		-
	Cash			-	50	(6)	-		50		11		12	(7)	-		23
Total at fair value				-	10,375		595		10,970		433		17,377		581		18,391
	Insurance contracts
		at contract value							15								26
Total plan assets									10,985								18,417

(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 Level 2 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 Public 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 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 input.

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

			U.S. Pension							Non-U.S. Pension
			Fair Value Measurement							Fair Value Measurement
			at December 31, 2014, Using:							at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	2,331	(1)	-		2,331		-		3,284	(1)	-		3,284
		Non-U.S.		-	2,144	(1)	-		2,144		229	(2)	3,776	(1)	-		4,005
	Private equity			-	-		562	(3)	562		-		-		535	(3)	535
	Debt securities
		Corporate		-	4,841	(4)	-		4,841		-		2,686	(4)	-		2,686
		Government		-	2,890	(4)	-		2,890		249	(5)	9,050	(4)	-		9,299
		Asset-backed		-	5	(4)	-		5		-		146	(4)	-		146
	Real estate funds			-	-		-		-		-		-		57	(6)	57
	Cash			-	131	(7)	-		131		25		31	(8)	-		56
Total at fair value				-	12,342		562		12,904		503		18,973		592		20,068
	Insurance contracts
		at contract value							11								27
Total plan assets									12,915								20,095

(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 Level 2 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 Public 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 input.

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

Fair Value Of The Benefit Plan Assets (Other Postretirement)

			Other Postretirement
				Fair Value Measurement
			at December 31, 2015, Using:
				Level 1	Level 2		Level 3	Total
				(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	96	(1)	-	96
		Non-U.S.		-	67	(1)	-	67
	Private equity			-	-		-	-
	Debt securities
		Corporate		-	79	(2)	-	79
		Government		-	170	(2)	-	170
		Asset-backed		-	1	(2)	-	1
	Cash			-	1		-	1
Total at fair value				-	414		-	414

(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 Level 2 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 corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

			Other Postretirement
			Fair Value Measurement
			at December 31, 2014, Using:
				Level 1	Level 2		Level 3		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	106	(1)	-		106
		Non-U.S.		-	75	(1)	-		75
	Private equity			-	-		2	(2)	2
	Debt securities
		Corporate		-	103	(3)	-		103
		Government		-	171	(3)	-		171
		Asset-backed		-	9	(3)	-		9
	Cash			-	2		-		2
Total at fair value				-	466		2		468

(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 Level 2 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 Public Offerings.

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

Change In Fair Value Of Level 3 Assets

	2015
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	562	535	57	2
Net realized gains/(losses)	1	26	(5)	-
Net unrealized gains/(losses)	106	64	-	-
Net purchases/(sales)	(74)	(44)	(52)	(2)
Fair value at December 31	595	581	-	-

	2014
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	523	502	136	9
Net realized gains/(losses)	2	23	(17)	-
Net unrealized gains/(losses)	89	31	8	-
Net purchases/(sales)	(52)	(21)	(70)	(7)
Fair value at December 31	562	535	57	2

Pension Plans With Accumulated Benefit Obligation In Excess Of Plan Assets

		Pension Benefits
		U.S.			Non-U.S.
			2015	2014		2015	2014
		(millions of dollars)
For funded pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		16,767	17,505		1,827	5,031
	Accumulated benefit obligation		13,913	14,493		1,373	4,590
	Fair value of plan assets		10,985	12,915		1,299	3,890
For unfunded pension plans:
	Projected benefit obligation		2,816	3,024		6,112	7,839
	Accumulated benefit obligation		1,753	1,892		5,290	6,573

Estimated Next Year Amortization

					Other
			Pension Benefits		Postretirement
			U.S.	Non-U.S.	Benefits
		(millions of dollars)
Estimated 2016 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain) (1)		930	543		152
	Prior service cost (2)		6	55		(30)

(1) The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service 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 other postretirement benefit plans.

Expected Contributions and Benefit Payments for Pension Benefits And Other Postretirement Benefits

		Pension Benefits		Other Postretirement Benefits
					Medicare
		U.S.	Non-U.S.	Gross	Subsidy Receipt
		(millions of dollars)
Contributions expected in 2016		2,000	525	-		-
Benefit payments expected in:
	2016	1,548	1,145	457		24
	2017	1,491	1,128	470		25
	2018	1,411	1,178	481		26
	2019	1,382	1,193	490		28
	2020	1,342	1,227	497		29
	2021 - 2025	6,594	6,359	2,518		170

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Disclosures About Segments And Related Information (Tables)

12 Months Ended

Dec. 31, 2015

Disclosures About Segments And Related Information [Abstract]

Disclosures About Segments And Related Information

													Corporate
	Upstream				Downstream				Chemical					and	Corporate
	U.S.		Non-U.S.		U.S.		Non-U.S.		U.S.		Non-U.S.		Financing			Total
		(millions of dollars)
As of December 31, 2015
Earnings after income tax		(1,079)		8,180		1,901		4,656		2,386		2,032		(1,926)		16,150
Earnings of equity companies included above		226		5,831		170		444		144		1,235		(406)		7,644
Sales and other operating revenue (1)		8,241		15,812		73,063		134,230		10,880		17,254		8		259,488
Intersegment revenue		4,344		20,839		12,440		22,166		7,442		5,168		274		-
Depreciation and depletion expense		5,301		9,227		664		1,003		375		654		824		18,048
Interest revenue		-		-		-		-		-		-		46		46
Interest expense		26		27		8		4		-		1		245		311
Income taxes		(879)		4,703		866		1,325		646		633		(1,879)		5,415
Additions to property, plant and equipment		6,915		14,561		916		1,477		1,865		629		1,112		27,475
Investments in equity companies		5,160		10,980		95		1,179		125		3,025		(227)		20,337
Total assets		93,648		155,316		16,498		29,808		10,174		18,236		13,078		336,758
As of December 31, 2014
Earnings after income tax		5,197		22,351		1,618		1,427		2,804		1,511		(2,388)		32,520
Earnings of equity companies included above		1,235		10,859		29		82		186		1,377		(445)		13,323
Sales and other operating revenue (1)		14,826		22,336		118,771		199,976		15,115		23,063		18		394,105
Intersegment revenue		7,723		38,846		17,281		44,231		10,117		8,098		274		-
Depreciation and depletion expense		5,139		8,523		654		1,228		370		645		738		17,297
Interest revenue		-		-		-		-		-		-		75		75
Interest expense		40		17		6		4		-		-		219		286
Income taxes		1,300		15,165		610		968		1,032		358		(1,418)		18,015
Additions to property, plant and equipment		9,098		19,225		1,050		1,356		1,564		564		1,399		34,256
Investments in equity companies		5,089		10,877		69		1,006		258		3,026		(308)		20,017
Total assets		92,555		161,033		18,371		33,299		8,798		18,449		16,988		349,493
As of December 31, 2013
Earnings after income tax		4,191		22,650		2,199		1,250		2,755		1,073		(1,538)		32,580
Earnings of equity companies included above		1,576		11,627		(460)		22		189		1,422		(449)		13,927
Sales and other operating revenue (1)		13,712		25,349		123,802		218,904		15,295		23,753		21		420,836
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		17,182
Interest revenue		-		-		-		-		-		-		87		87
Interest expense		30		26		7		8		1		-		(63)		9
Income taxes		2,197		21,554		721		481		989		363		(2,042)		24,263
Additions to property, plant and equipment		7,480		26,075		616		1,072		840		272		1,386		37,741
Investments in equity companies		4,975		9,740		62		1,749		217		3,103		(227)		19,619
Total assets		88,698		157,465		19,261		40,661		7,816		19,659		13,248		346,808

(1) Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015,$29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

Geographic Sales And Other Operating Revenue

Geographic
Sales and other operating revenue (1)		2015	2014	2013
		(millions of dollars)
United States		92,184	148,713	152,820
Non-U.S.		167,304	245,392	268,016
	Total	259,488	394,105	420,836
Significant non-U.S. revenue sources include:
	United Kingdom	23,651	31,346	34,061
	Canada	22,876	36,072	35,924
	Italy	13,795	18,880	19,273
	Belgium	13,154	20,953	20,973
	France	11,808	17,639	18,444
	Singapore	10,790	15,407	15,623
	Germany	10,045	14,816	15,701

(1) Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

Schedule Of Long-Lived Assets By Geographic Regions

Long-lived assets		2015	2014	2013
		(millions of dollars)
United States		107,039	104,000	98,271
Non-U.S.		144,566	148,668	145,379
	Total	251,605	252,668	243,650
Significant non-U.S. long-lived assets include:
	Canada	39,775	43,858	41,522
	Australia	15,894	15,328	14,258
	Nigeria	12,222	12,265	12,343
	Kazakhstan	9,705	9,138	8,530
	Singapore	9,681	9,620	9,570
	Angola	8,777	9,057	8,262
	Papua New Guinea	5,985	6,099	5,768

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Income, Sales-Based And Other Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income, Sales-Based And Other Taxes [Abstract]

Schedule Of Income, Sales-Based And Other Taxes

						2015				2014				2013
				U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total
								(millions of dollars)
Income tax expense
	Federal and non-U.S.
		Current		-		7,126	7,126	1,456		14,755	16,211	1,073		22,115	23,188
		Deferred - net		(1,166)		(571)	(1,737)	900		1,398	2,298	(116)		757	641
	U.S. tax on non-U.S. operations			38		-	38	5		-	5	37		-	37
			Total federal and non-U.S.	(1,128)		6,555	5,427	2,361		16,153	18,514	994		22,872	23,866
	State (1)			(12)		-	(12)	(499)		-	(499)	397		-	397
			Total income tax expense	(1,140)		6,555	5,415	1,862		16,153	18,015	1,391		22,872	24,263
Sales-based taxes				6,402		16,276	22,678	6,310		23,032	29,342	5,992		24,597	30,589
All other taxes and duties
	Other taxes and duties			162		27,103	27,265	378		31,908	32,286	955		32,275	33,230
	Included in production and
		manufacturing expenses		1,157		828	1,985	1,454		1,179	2,633	1,318		1,182	2,500
	Included in SG&A expenses			150		390	540	155		441	596	150		516	666
		Total other taxes and duties		1,469		28,321	29,790	1,987		33,528	35,515	2,423		33,973	36,396
			Total	6,731		51,152	57,883	10,159		72,713	82,872	9,806		81,442	91,248

(1)In 2014, state taxes included a favorable adjustment of deferred taxes of approximately $830 million.

Reconciliation Between Income Tax Expense And A Theoretical U.S. Tax

			2015	2014	2013
			(millions of dollars)
Income before income taxes
	United States		147	9,080	9,746
	Non-U.S.		21,819	42,550	47,965
		Total	21,966	51,630	57,711
Theoretical tax			7,688	18,071	20,199
Effect of equity method of accounting			(2,675)	(4,663)	(4,874)
Non-U.S. taxes in excess of theoretical U.S. tax			1,415	5,442	10,528
U.S. tax on non-U.S. operations			38	5	37
State taxes, net of federal tax benefit			(8)	(324)	258
Other			(1,043)	(516)	(1,885)
		Total income tax expense	5,415	18,015	24,263
Effective tax rate calculation
Income taxes			5,415	18,015	24,263
ExxonMobil share of equity company income taxes			3,011	5,678	6,061
		Total income taxes	8,426	23,693	30,324
Net income including noncontrolling interests			16,551	33,615	33,448
		Total income before taxes	24,977	57,308	63,772
Effective income tax rate			34%	41%	48%

Deferred Tax Liabilities/(Assets)

Tax effects of temporary differences for:		2015	2014
		(millions of dollars)
Property, plant and equipment		49,409	51,643
Other liabilities		4,613	4,359
	Total deferred tax liabilities	54,022	56,002
Pension and other postretirement benefits		(6,286)	(8,140)
Asset retirement obligations		(6,277)	(6,162)
Tax loss carryforwards		(4,983)	(4,099)
Other assets		(5,592)	(6,446)
	Total deferred tax assets	(23,138)	(24,847)
Asset valuation allowances		1,730	2,570
	Net deferred tax liabilities	32,614	33,725

Deferred Income Tax (Assets) And Liabilities By Balance Sheet Classification

Balance sheet classification		2015	2014
		(millions of dollars)
Other current assets		(1,329)	(2,001)
Other assets, including intangibles, net		(3,421)	(3,955)
Accounts payable and accrued liabilities		546	451
Deferred income tax liabilities		36,818	39,230
	Net deferred tax liabilities	32,614	33,725

Unrecognized Tax Benefits

Gross unrecognized tax benefits		2015	2014	2013
		(millions of dollars)
Balance at January 1		8,986	7,838	7,663
	Additions based on current year's tax positions	903	1,454	1,460
	Additions for prior years' tax positions	496	448	464
	Reductions for prior years' tax positions	(190)	(532)	(249)
	Reductions due to lapse of the statute of limitations	(4)	(117)	(588)
	Settlements with tax authorities	(725)	(43)	(849)
	Foreign exchange effects/other	(70)	(62)	(63)
Balance at December 31		9,396	8,986	7,838

Remaining Tax Years Subject To Examination By Major Tax Jurisdiction

Country of Operation	Open Tax Years
Abu Dhabi	2012 - 2015
Angola	2009 - 2015
Australia	2005, 2008 - 2015
Canada	2008 - 2015
Equatorial Guinea	2007 - 2015
Malaysia	2009 - 2015
Nigeria	2005 - 2015
Norway	2007 - 2015
Qatar	2009 - 2015
Russia	2012 - 2015
United Kingdom	2011 - 2015
United States	2006 - 2015

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Miscellaneous Financial Information (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Miscellaneous Financial Information [Abstract]
Research and development expense	$ 1,008,000,000	$ 971,000,000	$ 1,044,000,000
Foreign currency transaction gain/(loss), before tax	(119,000,000)	(225,000,000)	155,000,000
Gains/(losses) on combined effects of LIFO inventory accumulations and draw-downs	(186,000,000)	187,000,000	$ 282,000,000
Replacement cost of inventories estimated to exceed LIFO carrying values	$ 4,500,000,000	$ 10,600,000,000

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Miscellaneous Financial Information (Crude Oil, Products And Merchandise) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Miscellaneous Financial Information [Abstract]
Crude oil	$ 4,200	$ 4,600
Petroleum products	4,100	4,100
Chemical products	2,700	2,900
Gas / other	1,000	800
Total	$ 12,037	$ 12,384

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Other Comprehensive Income Information (Schedule of Accumulated Other Comprehensive Income Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current period change excluding amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	$ (9,303)	$ (5,847)	$ (3,620)
Amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(14)	152	(23)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	2,358	(4,262)	3,174
Amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	1,448	1,111	1,820
Current period change excluding amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	33	(63)
Amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	27	3
Beginning Balance, Total	(18,957)
Ending Balance, Total	(23,511)	(18,957)
Exxon Mobil Corporation Share After Noncontrolling Interest [Member]
Beginning Balance, Cumulative Foreign Exchange Translation Adjustment	(5,952)	(846)	2,410
Current period change excluding amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(8,204)	(5,258)	(3,233)
Amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(14)	152	(23)
Total change in accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(8,218)	(5,106)	(3,256)
Ending Balance, Cumulative Foreign Exchange Translation Adjustment	(14,170)	(5,952)	(846)
Beginning Balance, Postretirement Benefits Reserves Adjustment	(12,945)	(9,879)	(14,594)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	2,202	(4,132)	2,963
Amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	1,402	1,066	1,752
Total change in accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	3,604	(3,066)	4,715
Ending Balance, Postretirement Benefits Reserves Adjustment	(9,341)	(12,945)	(9,879)
Beginning Balance, Unrealized Change in Stock Investments	(60)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	33	(63)
Amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	27	3
Total change in accumulated other comprehensive income, Unrealized Change in Stock Investments	60	(60)
Ending Balance, Unrealized Change in Stock Investments		(60)
Beginning Balance, Total	(18,957)	(10,725)	(12,184)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Total	(5,969)	(9,453)	(270)
Amounts reclassified from accumulated other comprehensive income, Total	1,415	1,221	1,729
Total other comprehensive income	(4,554)	(8,232)	1,459
Ending Balance, Total	$ (23,511)	$ (18,957)	$ (10,725)

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Other Comprehensive Income Information (Amounts Reclassified Out Of Acc Other Comp Income) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive Income Information Before Tax [Abstract]
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other income)		$ 14	$ (152)	$ 23
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	[1]	(2,066)	(1,571)	$ (2,616)
Realized change in fair value of stock investments included in net income (Statement of Income line: Other income)		$ (42)	$ (5)

[1] These accumulated other comprehensive income components are included in the computation of net periodic pension cost. (See Note 17 – Pension and Other Postretirement Benefits for additional details.)

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Other Comprehensive Income Information (Schedule Of Income Tax (Expense)/Credit For Components Of Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Comprehensive Income Information Tax [Abstract]
Foreign exchange translation adjustment	$ 170	$ 292	$ 218
Postretirement benefits reserves adjustment (excluding amortization)	(1,192)	2,009	(1,540)
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	(618)	(460)	(796)
Unrealized change in fair value of stock investments	(17)	34
Realized change in fair value of stock investments included in net income	(15)	(2)
Total	$ (1,672)	$ 1,873	$ (2,118)

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Cash Flow Information (Cash Payments For Interest And Income Taxes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flow Information [Abstract]
Cash payments for interest	$ 586	$ 380	$ 426
Cash payments for income taxes	7,269	18,085	25,066
Proceeds from sales of assets	2,389	4,035	$ 2,707
Asset Exchange [Member]
Asset exchanges, primarily noncash	500	$ 1,200
Proceeds from sales of assets	100
Capital lease obligations incurred	1,000
Maturity Greater Than Three Months [Member]
Net cash flow from issuance/(repayment) of commercial paper	358
Proceeds from issuance of commercial paper	8,100
Repayments of commercial paper	$ 7,700

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Additional Working Capital Information (Narrative) (Details) - USD ($) $ in Billions	Dec. 31, 2015	Dec. 31, 2014
Line Of Credit Facility [Line Items]
Weighted-average interest rate on short-term borrowings outstanding	0.40%	0.30%
Short Term Financing [Member]
Line Of Credit Facility [Line Items]
Unused credit lines	$ 6.0

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Additional Working Capital Information (Schedule Of Notes, Accounts Receivable And Payable, Loans Payable, Accrued Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Additional Working Capital Information [Abstract]
Trade notes and accounts receivable, less reserves of $107 million and $113 million	$ 13,243	$ 18,541
Other notes and accounts receivable, less reserves of $4 million and $48 million	6,632	9,468
Total notes and accounts receivable	19,875	28,009
Bank loans	231	473
Commercial paper	17,973	16,225
Long-term debt due within one year	558	770
Total notes and loans payable	18,762	17,468
Trade payables	18,074	25,286
Payables to equity companies	4,639	6,589
Accrued taxes other than income taxes	2,937	3,290
Other accounts payable and accrued liabilities	6,762	7,062
Total accounts payable and accrued liabilities	32,412	42,227
Trade notes and accounts receivable, reserves	107	113
Other notes and accounts receivable, reserves	$ 4	$ 48

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Equity Company Information (Narrative) (Details) - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Share of equity company sales revenues from sales to consolidated companies	15.00%	14.00%	13.00%
Rosneft VIE Joint Venture [Member]
Schedule of Equity Method Investments [Line Items]
Maximum before-tax exposure to loss from Rosneft JV's	$ 1.0

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Equity Company Information (Schedule Of Equity Company Financial Summary) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsidiary or Equity Method Investee [Line Items]
Net assets	$ 20,337	$ 20,017	$ 19,619
ExxonMobil Share Of Equity [Member]
Subsidiary or Equity Method Investee [Line Items]
Total revenues	34,297	55,855	68,084
Income before income taxes	10,670	19,014	19,999
Income taxes	3,019	5,684	6,069
Income from equity affiliates	7,651	13,330	13,930
Current assets	11,244	16,802	19,545
Long-term assets	32,878	33,619	35,695
Total assets	44,122	50,421	55,240
Current liabilities	6,738	11,472	15,243
Long-term liabilities	17,165	19,470	20,873
Net assets	20,219	19,479	19,124
Total Equity Company Including All Owners [Member]
Subsidiary or Equity Method Investee [Line Items]
Total revenues	111,866	183,708	236,161
Income before income taxes	36,379	65,549	69,454
Income taxes	11,048	20,520	21,618
Income from equity affiliates	25,331	45,029	47,836
Current assets	32,879	49,905	62,398
Long-term assets	109,684	110,754	116,450
Total assets	142,563	160,659	178,848
Current liabilities	22,947	37,333	54,550
Long-term liabilities	60,388	66,231	68,857
Net assets	$ 59,228	$ 57,095	$ 55,441

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Equity Company Information (Schedule Of The Corporation's Percentage Ownership Interest) (Details)	Dec. 31, 2015
Upstream [Member] | Aera Energy LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	48.00%
Upstream [Member] | BEB Erdgas und Erdoel GmbH & Co. KG [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Upstream [Member] | Cameroon Oil Transportation Company S.A. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	41.00%
Upstream [Member] | Cross Timbers Energy, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Upstream [Member] | Golden Pass LNG Terminal LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	18.00%
Upstream [Member] | Karmorneftegaz Holding SARL [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	33.00%
Upstream [Member] | Marine Well Containment Company LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	10.00%
Upstream [Member] | Nederlandse Aardolie Maatschappij B.V. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Upstream [Member] | Qatar Liquefied Gas Company Limited [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	10.00%
Upstream [Member] | Qatar Liquefied Gas Company Limited (2) [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	24.00%
Upstream [Member] | Ras Laffan Liquefied Natural Gas Company Limited [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	25.00%
Upstream [Member] | Ras Laffan Liquefied Natural Gas Company Limited (II) [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	31.00%
Upstream [Member] | Ras Laffan Liquefied Natural Gas Company Limited (3) [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	30.00%
Upstream [Member] | South Hook LNG Terminal Company Limited [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	24.00%
Upstream [Member] | Tengizchevroil, LLP [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	25.00%
Upstream [Member] | Terminale GNL Adriatico S.r.l. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	71.00%
Downstream [Member] | Fujian Refining & Petrochemical Co. Ltd. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	25.00%
Downstream [Member] | Saudi Aramco Mobil Refinery Company Ltd. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Chemical [Member] | Al-Jubail Petrochemical Company [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Chemical [Member] | Infineum Holdings B.V. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Chemical [Member] | Infineum Italia s.r.l. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Chemical [Member] | Infineum USA L.P. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
Chemical [Member] | Saudi Yanbu Petrochemical Co. [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%

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Investments, Advances And Long-Term Receivables (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investments, Advances And Long-Term Receivables [Abstract]
Investments (Companies carried at equity in underlying assets)	$ 20,337	$ 20,017	$ 19,619
Advances (Companies carried at equity in underlying assets)	9,110	9,818
Total equity company investments and advances	29,447	29,835
Companies carried at cost or less and stock investments carried at fair value	274	526
Long-term receivables and miscellaneous investments at cost or less, net of reserves of $3,040 million and $2,662 million	4,524	4,878
Total	34,245	35,239
Reserves for long-term receivables and miscellaneous investments	$ 3,040	$ 2,662

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Property, Plant And Equipment And Asset Retirement Obligations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Accumulated depreciation and depletion		$ 195,732	$ 194,121
Interest capitalized		$ 482	$ 344	$ 309
Downstream [Member] | Refinery And Lubes Basestock Manufacturing Facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years		25 years
Downstream [Member] | Service Station Buildings And Fixed Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years		20 years
Chemical [Member] | Investments In Process Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years	25 years	20 years

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Property, Plant And Equipment And Asset Retirement Obligations (Property, Plant And Equipment) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	$ 447,337	$ 446,789
Property, Plant and Equipment, Net	251,605	252,668	$ 243,650
Upstream [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	347,821	347,170
Property, Plant and Equipment, Net	203,822	205,308
Downstream [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	50,742	53,327
Property, Plant and Equipment, Net	21,330	22,639
Chemical [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	32,481	30,717
Property, Plant and Equipment, Net	16,247	14,918
Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	16,293	15,575
Property, Plant and Equipment, Net	$ 10,206	$ 9,803

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Property, Plant And Equipment And Asset Retirement Obligations (Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant And Equipment And Asset Retirement Obligations [Abstract]
Beginning balance	$ 13,424	$ 12,988
Accretion expense and other provisions	775	871
Reduction due to property sales	(208)	(151)
Payments made	(928)	(724)
Liabilities incurred	283	122
Foreign currency translation	(931)	(908)
Revisions	1,289	1,226
Ending balance	$ 13,704	$ 13,424

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Accounting For Suspended Exploratory Well Costs (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Exploratory Wells Drilled [Line Items]
Number of projects that have exploratory well costs capitalized for a period greater than twelve months as of December 31, 2015	55	53	50
Number of projects that have drilling in the preceding twelve months or exploratory activity either planned in the next two years or subject to sanctions as of December 31, 2015	18
Number of projects with completed exploratory activity progressing toward development as of December 31, 2015	37
Capitalized exploratory well costs	$ 4,372	$ 3,587	$ 2,707	$ 2,679
Total 37 Projects [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 1,154

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Accounting For Suspended Exploratory Well Costs (Change In Capitalized Suspended Exploratory Well Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting For Suspended Exploratory Well Costs [Abstract]
Capitalized suspended exploratory well costs, beginning balance	$ 3,587	$ 2,707	$ 2,679
Additions pending the determination of proved reserves	847	1,095	293
Charged to expense	(5)	(28)	(52)
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(43)	(160)	(107)
Divestments/Other	(14)	(27)	(106)
Capitalized suspended exploratory well costs, ending balance	4,372	3,587	2,707
Ending balance attributed to equity companies included above	$ 696	$ 645	$ 13

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Accounting For Suspended Exploratory Well Costs (Schedule Of Period End Capitalized Suspended Exploratory Well Costs) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized for a period of one year or less	$ 847	$ 1,095	$ 293
Capitalized for a period greater than one year - subtotal	3,525	2,492	2,414
Capitalized suspended exploratory well costs, total	4,372	3,587	2,707	$ 2,679
Capitalized For A Period Of Between One And Five Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized for a period greater than one year - subtotal	2,386	1,659	1,705
Capitalized For A Period Of Between Five And Ten Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized for a period greater than one year - subtotal	826	544	470
Capitalized For A Period Of Greater Than Ten Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized for a period greater than one year - subtotal	$ 313	$ 289	$ 239

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Accounting For Suspended Exploratory Well Costs (Schedule Of Number Of Projects With Suspended Exploratory Well Costs) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting For Suspended Exploratory Well Costs [Abstract]
Number of projects with first capitalized well drilled in the preceding 12 months	4	8	8
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months	55	53	50
Total	59	61	58

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Accounting For Suspended Exploratory Well Costs (Schedule Of Additional Detail For The Projects) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 4,372	$ 3,587	$ 2,707	$ 2,679
Total 37 Projects [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	1,154
Angola [Member] | Project In Angola - Kaombo Split Hub Phase 2[Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 20
Angola [Member] | Project In Angola - Kaombo Split Hub Phase 2[Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2005
Angola [Member] | Project In Angola - Kaombo Split Hub Phase 2[Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Angola [Member] | Project In Angola - Perpetua-Zinia- Acacia [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 15
Angola [Member] | Project In Angola - Perpetua-Zinia- Acacia [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Angola [Member] | Project In Angola - Perpetua-Zinia- Acacia [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Australia [Member] | Project In Australia - East Pilchard [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 7
Australia [Member] | Project In Australia - East Pilchard [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2001
Australia [Member] | Project In Australia - East Pilchard [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2001
Australia [Member] | Project In Australia - SE Longtom [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 11
Australia [Member] | Project In Australia - SE Longtom [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Australia [Member] | Project In Australia - SE Longtom [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Australia [Member] | Project in Australia - SE Remora [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 34
Australia [Member] | Project in Australia - SE Remora [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Australia [Member] | Project in Australia - SE Remora [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Canada [Member] | Project in Canada - Horn River
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 241
Canada [Member] | Project in Canada - Horn River | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Canada [Member] | Project in Canada - Horn River | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2012
Indonesia [Member] | Project In Indonesia - Alas Tua West [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 16
Indonesia [Member] | Project In Indonesia - Alas Tua West [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Indonesia [Member] | Project In Indonesia - Alas Tua West [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
Indonesia [Member] | Project In Indonesia - Cepu Gas [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 29
Indonesia [Member] | Project In Indonesia - Cepu Gas [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Indonesia [Member] | Project In Indonesia - Cepu Gas [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2011
Indonesia [Member] | Project in Indonesia - Kedung Keris [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 11
Indonesia [Member] | Project in Indonesia - Kedung Keris [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2011
Indonesia [Member] | Project in Indonesia - Kedung Keris [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2011
Indonesia [Member] | Project In Indonesia - Natuna [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 118
Indonesia [Member] | Project In Indonesia - Natuna [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1981
Indonesia [Member] | Project In Indonesia - Natuna [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1983
Kazakhstan [Member] | Project In Kazakhstan - Kairan [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 53
Kazakhstan [Member] | Project In Kazakhstan - Kairan [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2004
Kazakhstan [Member] | Project In Kazakhstan - Kairan [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2007
Kazakhstan [Member] | Project in Kazakhstan - Kalamkas
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 18
Kazakhstan [Member] | Project in Kazakhstan - Kalamkas | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Kazakhstan [Member] | Project in Kazakhstan - Kalamkas | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Malaysia [Member] | Project in Malaysia - Bindu [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 2
Malaysia [Member] | Project in Malaysia - Bindu [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1995
Malaysia [Member] | Project in Malaysia - Bindu [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1995
Nigeria [Member] | Project In Nigeria - Bolia [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 15
Nigeria [Member] | Project In Nigeria - Bolia [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2002
Nigeria [Member] | Project In Nigeria - Bolia [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Nigeria [Member] | Project In Nigeria - Bosi [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 79
Nigeria [Member] | Project In Nigeria - Bosi [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2002
Nigeria [Member] | Project In Nigeria - Bosi [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Nigeria [Member] | Project in Nigeria - Bosi Central [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 16
Nigeria [Member] | Project in Nigeria - Bosi Central [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Nigeria [Member] | Project in Nigeria - Bosi Central [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2006
Nigeria [Member] | Project in Nigeria - Erha Northeast [Member}
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 26
Nigeria [Member] | Project in Nigeria - Erha Northeast [Member} | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Nigeria [Member] | Project in Nigeria - Erha Northeast [Member} | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Nigeria [Member] | Project In Nigeria - Pegi [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 32
Nigeria [Member] | Project In Nigeria - Pegi [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Nigeria [Member] | Project In Nigeria - Pegi [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Nigeria [Member] | Project in Nigeria - Satellite Field Development Phase 2 [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 12
Nigeria [Member] | Project in Nigeria - Satellite Field Development Phase 2 [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2013
Nigeria [Member] | Project in Nigeria - Satellite Field Development Phase 2 [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2013
Nigeria [Member] | Other 4 Projects In Nigeria [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 14
Nigeria [Member] | Other 4 Projects In Nigeria [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2002
Nigeria [Member] | Other 4 Projects In Nigeria [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2002
Norway [Member] | Project in Norway - Gamma [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 13
Norway [Member] | Project in Norway - Gamma [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Norway [Member] | Project in Norway - Gamma [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Norway [Member] | Project In Norway - Lavrans [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 15
Norway [Member] | Project In Norway - Lavrans [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1995
Norway [Member] | Project In Norway - Lavrans [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1999
Norway [Member] | Other 7 Projects In Norway [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 25
Norway [Member] | Other 7 Projects In Norway [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2008
Norway [Member] | Other 7 Projects In Norway [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2014
Papua New Guinea [Member] | Project In Papua New Guinea - Juha [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 28
Papua New Guinea [Member] | Project In Papua New Guinea - Juha [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2007
Papua New Guinea [Member] | Project In Papua New Guinea - Juha [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2007
Republic of Congo [Member] | Project In Republic of Congo - Mer Tres Profonde Sud [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 56
Republic of Congo [Member] | Project In Republic of Congo - Mer Tres Profonde Sud [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2000
Republic of Congo [Member] | Project In Republic of Congo - Mer Tres Profonde Sud [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2007
United Kingdom [Member] | Project In United Kingdom - Phyllis [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 8
United Kingdom [Member] | Project In United Kingdom - Phyllis [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2004
United Kingdom [Member] | Project In United Kingdom - Phyllis [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2004
United States [Member] | Project In United States - Hadrian North [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 209
United States [Member] | Project In United States - Hadrian North [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
United States [Member] | Project In United States - Hadrian North [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2013
United States [Member] | Project in United States - Tip Top [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 31
United States [Member] | Project in United States - Tip Top [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
United States [Member] | Project in United States - Tip Top [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009

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Leased Facilities (Narrative) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Leased Facilities [Abstract]
Minimum undiscounted lease commitments	$ 4,877
Estimated related rental income from noncancelable subleases	$ 32

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Leased Facilities (Leased Facilities) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Lease Payments Under Minimum Commitments, 2016	$ 1,653
Lease Payments Under Minimum Commitments, 2017	1,003
Lease Payments Under Minimum Commitments, 2018	555
Lease Payments Under Minimum Commitments, 2019	344
Lease Payments Under Minimum Commitments, 2020	265
Lease Payments Under Minimum Commitments, 2021 and beyond	1,057
Lease Payments Under Minimum Commitments, Total	4,877
Related Sublease Rental Income, 2016	7
Related Sublease Rental Income, 2017	6
Related Sublease Rental Income, 2018	2
Related Sublease Rental Income, 2019	2
Related Sublease Rental Income, 2020	2
Related Sublease Rental Income, 2021 and beyond	13
Related Sublease Rental Income, Total	32
Drilling Rigs and Related Equipment [Member]
Lease Payments Under Minimum Commitments, 2016	827
Lease Payments Under Minimum Commitments, 2017	408
Lease Payments Under Minimum Commitments, 2018	134
Lease Payments Under Minimum Commitments, 2019	89
Lease Payments Under Minimum Commitments, 2020	77
Lease Payments Under Minimum Commitments, 2021 and beyond	86
Lease Payments Under Minimum Commitments, Total	1,621
Other [Member]
Lease Payments Under Minimum Commitments, 2016	826
Lease Payments Under Minimum Commitments, 2017	595
Lease Payments Under Minimum Commitments, 2018	421
Lease Payments Under Minimum Commitments, 2019	255
Lease Payments Under Minimum Commitments, 2020	188
Lease Payments Under Minimum Commitments, 2021 and beyond	971
Lease Payments Under Minimum Commitments, Total	$ 3,256

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Leased Facilities (Net Rental Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Rental cost	$ 3,973	$ 4,077	$ 3,841
Less sublease rental income	44	52	44
Net rental cost	3,929	4,025	3,797
Lease Agreements Drilling Rigs And Related Equipment [Member]
Rental cost	1,853	1,763	1,424
Lease Agreements Other [Member]
Rental cost	$ 2,120	$ 2,314	$ 2,417

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings per common share
Net income attributable to ExxonMobil		$ 16,150	$ 32,520	$ 32,580
Weighted average number of common shares outstanding		4,196	4,282	4,419
Earnings per common share (dollars)	[1]	$ 3.85	$ 7.6	$ 7.37
Dividends paid per common share (dollars)		$ 2.88	$ 2.7	$ 2.46

[1] The earnings per common share and earnings per common share - assuming dilution are the same in each period shown.

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Financial Instruments And Derivatives (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		$ 18,900	$ 11,700
Recorded book values of total long-term debt, excluding capitalized lease obligations		18,700	11,300
Derivative asset at fair value, net		21	75
Gain (loss) before-tax earnings impact of derivatives		39	110	$ (7)
Additions to long-term debt	$ 8,000	8,028	$ 5,731	$ 345
Level 1 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		18,584
Level 2 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		208
Level 3 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		$ 62

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Long-Term Debt (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt due in U.S. dollars		$ 19,217
U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies		708
Portion of long-term debt included in current liability		558	$ 770
Long-term debt maturing - 2017		2,959
Long-term debt maturing - 2018		2,967
Long-term debt maturing - 2019		2,374
Long-term debt maturing - 2020		1,602
Additions to long-term debt	$ 8,000	8,028	$ 5,731	$ 345
Long Term Financing [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Unused credit lines		$ 400

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Long-Term Debt (Summarized Long-Term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument, Unamortized Premium		$ 179	$ 219
Long-term debt		19,925	11,653
Combined Exxon Mobil And Affiliates [Member] | Other U.S. Dollar Obligations [Member]
Other long-term debt	[1]	$ 97	$ 104
Average effective interest rate		3.80%	4.20%
Combined Exxon Mobil And Affiliates [Member] | Other Foreign Currency Obligations [Member]
Other long-term debt		$ 1	$ 9
0.921% Notes Due 2017 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,500	$ 1,500
Interest rate		0.921%	0.921%
Debt maturity		Mar. 15, 2017	Mar. 15, 2017
Floating-Rate Notes Due 2017 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	[2]	$ 750	$ 750
Debt maturity		Mar. 15, 2017	Mar. 15, 2017
Average effective interest rate		0.30%	0.30%
Floating-Rate Notes Due 2018 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	[3]	$ 500
Debt maturity		Mar. 01, 2018
Average effective interest rate		0.40%
1.305% Notes Due 2018 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,600
Interest rate		1.305%
Debt maturity		Mar. 06, 2018
1.819% Notes Due 2019 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,750	$ 1,750
Interest rate		1.819%	1.819%
Debt maturity		Mar. 15, 2019	Mar. 15, 2019
Floating-Rate Notes Due 2019 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	[4]	$ 500	$ 500
Debt maturity		Mar. 15, 2019	Mar. 15, 2019
Average effective interest rate		0.50%	0.40%
1.912% Notes Due 2020 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,500
Interest rate		1.912%
Debt maturity		Mar. 06, 2020
2.397% Notes Due 2022 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,150
Interest rate		2.397%
Debt maturity		Mar. 06, 2022
Floating-Rate Notes Due 2022 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	[5]	$ 500
Debt maturity		Mar. 06, 2022
Average effective interest rate		0.70%
3.176% Notes Due 2024 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,000	$ 1,000
Interest rate		3.176%	3.176%
Debt maturity		Mar. 15, 2024	Mar. 15, 2024
2.709% Notes Due 2025 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,750
Interest rate		2.709%
Debt maturity		Mar. 06, 2025
3.567% Notes Due 2045 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent		$ 1,000
Interest rate		3.567%
Debt maturity		Mar. 06, 2045
5.650% Senior Notes Due 2016 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent			$ 207
Interest rate			5.65%
Debt maturity			Apr. 01, 2016
6.250% Senior Notes Due 2017 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 465	$ 477
Interest rate		6.25%	6.25%
Debt maturity		Aug. 01, 2017	Aug. 01, 2017
5.500% Senior Notes Due 2018 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 377	$ 383
Interest rate		5.50%	5.50%
Debt maturity		Jun. 15, 2018	Jun. 15, 2018
6.500% Senior Notes Due 2018 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 463	$ 474
Interest rate		6.50%	6.50%
Debt maturity		Dec. 15, 2018	Dec. 15, 2018
6.100% Senior Notes Due 2036 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 198	$ 199
Interest rate		6.10%	6.10%
Debt maturity		Apr. 01, 2036	Apr. 01, 2036
6.750% Senior Notes Due 2037 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 307	$ 309
Interest rate		6.75%	6.75%
Debt maturity		Aug. 01, 2037	Aug. 01, 2037
6.375% Senior Notes Due 2038 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent		$ 235	$ 236
Interest rate		6.375%	6.375%
Debt maturity		Jun. 15, 2038	Jun. 15, 2038
Variable Notes Due 2016-2019 [Member] | Mobil Producing Nigeria Unlimited [Member]
Senior notes, noncurrent	[6]	$ 101	$ 399
Debt Instrument, maturity date range, start		Dec. 15, 2017	Jun. 15, 2016
Debt Instrument, maturity date range, end		Mar. 15, 2019	Mar. 15, 2019
Average effective interest rate		4.60%	4.50%
Variable Notes Due 2016-2020 [Member] | Esso (Thailand) Public Company Ltd. [Member]
Senior notes, noncurrent	[7]	$ 83	$ 121
Debt Instrument, maturity date range, start		Nov. 30, 2017	Nov. 30, 2017
Debt Instrument, maturity date range, end		May 10, 2020	Dec. 31, 2019
Average effective interest rate		2.10%	2.40%
Debentures Due 2021 [Member] | Mobil Corporation [Member]
Other long-term debt		$ 249	$ 249
Interest rate		8.625%	8.625%
Debt maturity		Aug. 15, 2021	Aug. 15, 2021
Industrial Revenue Bonds Due 2017-2051 [Member] | Combined Exxon Mobil And Affiliates [Member]
Other long-term debt	[8]	$ 2,611	$ 2,611
Debt Instrument, maturity date range, start		Apr. 01, 2017	Apr. 01, 2017
Debt Instrument, maturity date range, end		Dec. 01, 2051	Dec. 01, 2051
Average effective interest rate		0.02%	0.03%
Capitalized Lease Obligations [Member] | Combined Exxon Mobil And Affiliates [Member]
Average effective interest rate		9.20%	7.00%
Long-term debt	[9]	$ 1,238	$ 375

[1] Average effective interest rate of 3.8% in 2015 and 4.2% in 2014.

[2] Average effective interest rate of 0.3% in 2015 and 0.3% in 2014.

[3] Average effective interest rate of 0.4% in 2015.

[4] Average effective interest rate of 0.5% in 2015 and 0.4% in 2014.

[5] Average effective interest rate of 0.7% in 2015.

[6] Average effective interest rate of 4.6% in 2015 and 4.5% in 2014.

[7] Average effective interest rate of 2.1% in 2015 and 2.4% in 2014.

[8] Average effective interest rate of 0.02% in 2015 and 0.03% in 2014.

[9] Average imputed interest rate of 9.2% in 2015 and 7.0% in 2014.

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Incentive Program (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum ownership of affiliates needed for awards	50.00%
Number of shares issuable under 2003 incentive program, maximum	220,000,000
Remaining shares available for award under 2003 incentive program	100,000,000
Options and stock appreciation rights grant, minimum percentage of market value, date of grant	100.00%
Maximum Life Per Program Member [Member]
Share-based compensation arrangement by share-based payment award expiration period	10 years
Restricted Stock [Member]
Long-term incentive awards	9,681,000	9,775,000	9,729,000
Unrecognized compensation cost	$ 2,222
Unrecognized compensation cost, weighted-average period of recognition, years	4 years 6 months
Compensation cost charged against income	$ 855	$ 831	$ 854
Income tax benefit recognized in income	78	76	78
Fair value of shares/awards vested	808	946	1,040
Cash payments, vested restricted stock units	$ 64	$ 73	$ 67
Percent of the shares in each award vesting after three years	50.00%
Percent of the shares in each award vesting after seven years	50.00%
Percent of shares in each award vesting after five years	50.00%
Percent of shares in each award vesting in later of ten years or retirement	50.00%
Restricted Stock [Member] | Minimum [Member]
Vesting Period	3 years
Restricted Stock [Member] | Minimum [Member] | Executive Officer [Member]
Vesting Period	5 years
Restricted Stock [Member] | Maximum [Member]
Vesting Period	7 years
Restricted Stock [Member] | Maximum [Member] | Executive Officer [Member]
Vesting Period	10 years

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Incentive Program (Summary Of Restricted Stock And Units Outstanding) (Details) shares in Thousands	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Incentive Program [Abstract]
Issued and outstanding at January 1, Restricted stock, Shares | shares	44,439
2014 award issued in 2015, Shares | shares	9,758
Vested, Shares | shares	(9,945)
Forfeited, Shares | shares	(189)
Issued and outstanding at December 31, Restricted stock, Shares | shares	44,063
Issued and outstanding at January 1, Weighted Average Grant-Date Fair Value per Share | $ / shares	$ 81.45
2014 award issued in 2015, Weighted Average Grant-Date Fair Value per Share | $ / shares	95.2
Vested, Weighted Average Grant-Date Fair Value per Share | $ / shares	79.86
Forfeited, Weighted Average Grant-Date Fair Value per Share | $ / shares	82.26
Issued and outstanding at December 31, Weighted Average Grant-Date Fair Value per Share | $ / shares	$ 84.85

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Incentive Program (Grant Value Of Restricted Stock And Units) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Grant price, per share	$ 81.27	$ 95.2	$ 94.47
Restricted stock and units settled in stock	$ 727	$ 858	$ 843
Units settled in cash	60	73	76
Total value	$ 787	$ 931	$ 919

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Litigation And Other Contingencies (Narrative) (Details) - USD ($)	Oct. 09, 2014	Oct. 24, 2011	Jun. 27, 2007	May. 01, 2007
Mobil Cerro Negro, Ltd. (MCN) [Member] | Expropriation of Assets [Member]
Loss Contingencies [Line Items]
Percentage ownership interest in Cerro Negro Project			41.67%	41.67%
Interest compounded annually from date of expropriation until date of payment in full	3.25%
Final award related to Cerro Negro arbitration	$ 1,600,000,000
Earlier Cerro Negro award for breach of contractual obligations	$ 908,000,000
Production Sharing Contract (PSC) [Member]
Loss Contingencies [Line Items]
Percent interest in Erha block PSC		56.25%
Pending Or Threatened Litigation [Member]
Loss Contingencies [Line Items]
Amount of award relating to excess lifting of crude oil		$ 1,800,000,000
Accrued interest relating to award for excess lifting of crude oil		$ 234,000,000

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Litigation And Other Contingencies (Schedule Of Guarantees) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Loss Contingencies [Line Items]
Guarantees	$ 7,225
Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	2,637	[1]
Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	4,588
Debt-Related Guarantees [Member]
Loss Contingencies [Line Items]
Guarantees	133
Debt-Related Guarantees [Member] | Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	98	[1]
Debt-Related Guarantees [Member] | Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	35
Other Guarantees [Member]
Loss Contingencies [Line Items]
Guarantees	7,092
Other Guarantees [Member] | Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	2,539	[1]
Other Guarantees [Member] | Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	$ 4,553

[1] ExxonMobil share

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Litigation And Other Contingencies (Schedule Of Unconditional Purchase Obligations) (Details) $ in Millions	Dec. 31, 2015 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
2016	$ 133	[1]
2017-2020	493	[1]
2021 and Beyond	310	[1]
Total	936	[1]
Present value of these commitments	792
Undiscounted unconditional purchase obligations	936	[1]
Imputed interest	144
Equity Company Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	411
Undiscounted unconditional purchase obligations	$ 411

[1] Undiscounted obligations of $936 million mainly pertain to pipeline throughput agreements and include $411 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $144 million, totaled $792 million.

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Pension And Other Postretirement Benefits (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate projected in 2017	4.50%
Year that rate reaches ultimate trend rate	2017
Effect of one-percentage-point increase on service and interest costs	$ 88
Effect of one-percentage-point increase on postretirement benefit obligation	963
Effect of one-percentage-point decrease on service and interest costs	66
Effect of one-percentage-point decrease on postretirement benefit obligation	764
Costs for defined contribution plans	$ 405	$ 393	$ 392
Pension Benefits - U.S. [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	40.00%
Pension Benefits - U.S. [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	60.00%
Pension Benefits - U.S. [Member] | Venture Capital Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	5.00%
Pension Benefits - Non-U.S. [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	40.00%
Pension Benefits - Non-U.S. [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	60.00%
Pension Benefits - Non-U.S. [Member] | Venture Capital Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target asset allocation	3.00%

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Pension And Other Postretirement Benefits (Benefit Obligations And Plan Assets Associated With Principal Benefit Plans) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Medicare subsidy receipts		$ 15	$ 21
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.25%	4.00%
Long-term rate of compensation increase		5.75%	5.75%
Benefit obligation at January 1		$ 20,529	$ 17,304
Service cost		864	677	$ 801
Interest cost		785	807	749
Defined benefit plan, actuarial net (gains) losses		(545)	3,192
Amendments, divestments and other			(24)
Benefit obligation at December 31		19,583	20,529	17,304
Accumulated benefit obligation at December 31		$ 15,666	$ 16,385
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		3.60%	3.10%
Long-term rate of compensation increase		4.80%	5.30%
Benefit obligation at January 1		$ 30,047	$ 27,357
Service cost		689	590	697
Interest cost		850	1,138	1,076
Defined benefit plan, actuarial net (gains) losses		(1,517)	4,929
Foreign exchange rate changes		(3,242)	(2,540)
Amendments, divestments and other		(423)	(61)
Benefit obligation at December 31		25,117	30,047	27,357
Accumulated benefit obligation at December 31		$ 22,362	$ 26,318
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.25%	4.00%
Long-term rate of compensation increase		5.75%	5.75%
Benefit obligation at January 1		$ 9,436	$ 7,868
Service cost		170	140	176
Interest cost		346	383	352
Defined benefit plan, actuarial net (gains) losses		(617)	1,522
Foreign exchange rate changes		(106)	(48)
Amendments, divestments and other		(465)	96
Benefit obligation at December 31		8,282	9,436	$ 7,868
Benefit Payments For Funded And Unfunded Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1]	(2,050)	(1,427)
Benefit Payments For Funded And Unfunded Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1]	(1,287)	(1,366)
Benefit Payments For Funded And Unfunded Plans [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1],[2]	$ (482)	$ (525)

[1] Benefit payments for funded and unfunded plans.

[2] For 2015 and 2014, other postretirement benefits paid are net of $15 million and $21 million of Medicare subsidy receipts, respectively.

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Pension And Other Postretirement Benefits (Change In Plan Assets Of Pension And Other Postretirement Benefits) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1		$ 12,915	$ 11,190
Actual return on plan assets		(307)	1,497
Company contribution			1,476
Fair value at December 31		10,985	12,915
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1		20,095	19,283
Actual return on plan assets		918	3,153
Foreign exchange rate changes		(2,109)	(1,738)
Company contribution		515	554
Other		(112)	(245)
Fair value at December 31		18,417	20,095
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1		468	620
Actual return on plan assets			41
Company contribution		42	31
Fair value at December 31		414	468
Benefit Payments For Funded Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1]	(1,623)	(1,248)
Benefit Payments For Funded Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1]	(890)	(912)
Benefit Payments For Funded Plans [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	[1]	$ (96)	$ (224)

[1] Benefit payments for funded plans.

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Pension And Other Postretirement Benefits (Summary Of Assets In Excess Of/(Less Than) Benefit Obligation) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan funded status of plan		$ (5,782)	$ (4,590)
Unfunded plans		(2,816)	(3,024)
Total	[1]	(8,598)	(7,614)
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan funded status of plan		(588)	(2,113)
Unfunded plans		(6,112)	(7,839)
Total	[1]	$ (6,700)	$ (9,952)

[1] Fair value of assets less benefit obligation shown on the preceding page.

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Pension And Other Postretirement Benefits (Assets Recorded In Balance Sheet And Other Comprehensive Income) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Postretirement benefits reserves		$ (22,647)	$ (25,802)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	[1]	(8,598)	(7,614)
Current liabilities		(311)	(340)
Postretirement benefits reserves		(8,287)	(7,274)
Total recorded		(8,598)	(7,614)
Net actuarial loss/(gain)		6,138	6,589
Prior service cost		21	27
Total recorded in accumulated other comprehensive income		6,159	6,616
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	[1]	(6,700)	(9,952)
Other assets		454	302
Current liabilities		(299)	(325)
Postretirement benefits reserves		(6,855)	(9,929)
Total recorded		(6,700)	(9,952)
Net actuarial loss/(gain)		6,413	9,642
Prior service cost		(83)	429
Total recorded in accumulated other comprehensive income		6,330	10,071
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	[1]	(7,868)	(8,968)
Current liabilities		(363)	(369)
Postretirement benefits reserves		(7,505)	(8,599)
Total recorded		(7,868)	(8,968)
Net actuarial loss/(gain)		2,171	2,997
Prior service cost		(460)	51
Total recorded in accumulated other comprehensive income		$ 1,711	$ 3,048

[1] Fair value of assets less benefit obligation shown on the preceding page.

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Pension And Other Postretirement Benefits (Long-Term Rates Of Pension And Other Postretirement Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Total recorded in other comprehensive income	$ (5,535)	$ 4,619	$ (7,281)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%	5.00%	4.00%
Long-term rate of return on funded assets	7.00%	7.25%	7.25%
Long-term rate of compensation increase	5.75%	5.75%	5.75%
Service cost	$ 864	$ 677	$ 801
Interest cost	785	807	749
Expected return on plan assets	(830)	(799)	(835)
Amortization of actuarial loss/(gain)	544	409	646
Amortization of prior service cost	6	8	7
Net pension enhancement and curtailment/settlement cost	499	276	723
Net periodic benefit cost	1,868	1,378	2,091
Net actuarial loss/(gain)	592	2,494	(1,302)
Amortization of actuarial (loss)/gain	(1,043)	(685)	(1,369)
Prior service cost/(credit)		(25)
Amortization of prior service (cost)/credit	(6)	(8)	(7)
Total recorded in other comprehensive income	(457)	1,776	(2,678)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$ 1,411	$ 3,154	$ (587)
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.10%	4.30%	3.80%
Long-term rate of return on funded assets	5.90%	6.30%	6.40%
Long-term rate of compensation increase	5.30%	5.40%	5.50%
Service cost	$ 689	$ 590	$ 697
Interest cost	850	1,138	1,076
Expected return on plan assets	(1,094)	(1,193)	(1,128)
Amortization of actuarial loss/(gain)	730	628	852
Amortization of prior service cost	87	120	117
Net pension enhancement and curtailment/settlement cost	22		22
Net periodic benefit cost	1,284	1,283	1,636
Net actuarial loss/(gain)	(1,375)	2,969	(1,938)
Amortization of actuarial (loss)/gain	(752)	(628)	(874)
Prior service cost/(credit)	(401)	(70)	30
Amortization of prior service (cost)/credit	(87)	(120)	(117)
Foreign exchange rate changes	(1,126)	(688)	(155)
Total recorded in other comprehensive income	(3,741)	1,463	(3,054)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$ (2,457)	$ 2,746	$ (1,418)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%	5.00%	4.00%
Long-term rate of return on funded assets	7.00%	7.25%	7.25%
Long-term rate of compensation increase	5.75%	5.75%	5.75%
Service cost	$ 170	$ 140	$ 176
Interest cost	346	383	352
Expected return on plan assets	(28)	(37)	(41)
Amortization of actuarial loss/(gain)	206	116	228
Amortization of prior service cost	(24)	14	21
Net periodic benefit cost	670	616	736
Net actuarial loss/(gain)	(589)	1,518	(1,290)
Amortization of actuarial (loss)/gain	(206)	(116)	(228)
Prior service cost/(credit)	(535)
Amortization of prior service (cost)/credit	24	(14)	(21)
Foreign exchange rate changes	(31)	(8)	(10)
Total recorded in other comprehensive income	(1,337)	1,380	(1,549)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$ (667)	$ 1,996	$ (813)

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Pension And Other Postretirement Benefits (Summary Of The Change In Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	$ 5,535	$ (4,619)	$ 7,281
(Charge)/credit to income tax (see Note 4)	(1,810)	1,549	(2,336)
(Charge)/credit to investment in equity companies	81	(81)	49
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax	3,806	(3,151)	4,994
Charge/(credit) to equity of noncontrolling interests	(202)	85	(279)
Exxon Mobil Corporation Share After Noncontrolling Interest [Member]
Defined Benefit Plan Disclosure [Line Items]
Total change in accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	3,604	(3,066)	4,715
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	457	(1,776)	2,678
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	3,741	(1,463)	3,054
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	$ 1,337	$ (1,380)	$ 1,549

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Pension And Other Postretirement Benefits (Fair Value Of Benefit Plan Assets) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Insurance contracts at contract value		$ 15	$ 11
Fair value of plan assets		10,985	12,915	$ 11,190
Pension Benefits - U.S. [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,992	2,331
Pension Benefits - U.S. [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1,775	2,144
Pension Benefits - U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		595	562
Pension Benefits - U.S. [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		4,161	4,841
Pension Benefits - U.S. [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		2,394	2,890
Pension Benefits - U.S. [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3	5
Pension Benefits - U.S. [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		50	131
Pension Benefits - U.S. [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		10,970	12,904
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	1,992	2,331
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	1,775	2,144
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	4,161	4,841
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	2,394	2,890
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	3	5
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]	50	131
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 2 [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		10,375	12,342
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 3 [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	595	562
Pension Benefits - U.S. [Member] | Fair Value Inputs Level 3 [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		595	562
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Insurance contracts at contract value		26	27
Fair value of plan assets		18,417	20,095	$ 19,283
Pension Benefits - Non-U.S. [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3,179	3,284
Pension Benefits - Non-U.S. [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		3,608	4,005
Pension Benefits - Non-U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		581	535
Pension Benefits - Non-U.S. [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		2,561	2,686
Pension Benefits - Non-U.S. [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		8,368	9,299
Pension Benefits - Non-U.S. [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		71	146
Pension Benefits - Non-U.S. [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			57
Pension Benefits - Non-U.S. [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		23	56
Pension Benefits - Non-U.S. [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		18,391	20,068
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 1 [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[5]	179	229
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 1 [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[6]	243	249
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 1 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		11	25
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 1 [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		433	503
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	3,179	3,284
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	3,429	3,776
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	2,561	2,686
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	8,125	9,050
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	71	146
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[7]	12	31
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 2 [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		17,377	18,973
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 3 [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[4]	581	535
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 3 [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[8]		57
Pension Benefits - Non-U.S. [Member] | Fair Value Inputs Level 3 [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 581	$ 592

[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 Level 2 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 corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

[3] 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 input.

[4] For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

[5] For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

[6] For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

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

[8] For real estate funds, fair value is based on appraised values developed using comparable market transactions.

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Pension And Other Postretirement Benefits (Fair Value Of Benefit Plan Assets - Other Postretirement) (Details) - Other Postretirement Benefit Plans Defined Benefit [Member] - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 414	$ 468	$ 620
U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		96	106
Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		67	75
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			2
Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		79	103
Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		170	171
Asset Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1	9
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		1	2
Fair Value Inputs Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		414	466
Fair Value Inputs Level 2 [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	96	106
Fair Value Inputs Level 2 [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[1]	67	75
Fair Value Inputs Level 2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	79	103
Fair Value Inputs Level 2 [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	170	171
Fair Value Inputs Level 2 [Member] | Asset Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[2]	1	9
Fair Value Inputs Level 2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets		$ 1	2
Fair Value Inputs Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets			2
Fair Value Inputs Level 3 [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	[3]		$ 2

[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 Level 2 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 corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

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

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Pension And Other Postretirement Benefits (Change In The Fair Value Of Level 3 Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits - U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	$ 562	$ 523
Net realized gains/(losses)	1	2
Net unrealized gains/(losses)	106	89
Net purchases/(sales)	(74)	(52)
Fair value at December 31	595	562
Pension Benefits - Non-U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	535	502
Net realized gains/(losses)	26	23
Net unrealized gains/(losses)	64	31
Net purchases/(sales)	(44)	(21)
Fair value at December 31	581	535
Pension Benefits - Non-U.S. [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	57	136
Net realized gains/(losses)	(5)	(17)
Net unrealized gains/(losses)		8
Net purchases/(sales)	(52)	(70)
Fair value at December 31		57
Other Postretirement Benefits [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	2	9
Net purchases/(sales)	$ (2)	(7)
Fair value at December 31		$ 2

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Pension And Other Postretirement Benefits (Pension Plans With Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Funded Pension Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 16,767	$ 17,505
Accumulated benefit obligation	13,913	14,493
Fair value of plan assets	10,985	12,915
Funded Pension Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	1,827	5,031
Accumulated benefit obligation	1,373	4,590
Fair value of plan assets	1,299	3,890
Unfunded Pension Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	2,816	3,024
Accumulated benefit obligation	1,753	1,892
Unfunded Pension Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	6,112	7,839
Accumulated benefit obligation	$ 5,290	$ 6,573

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Pension And Other Postretirement Benefits (Estimated Amortization) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	$ 930	[1]
Prior service cost	6	[2]
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	543	[1]
Prior service cost	55	[2]
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	152	[1]
Prior service cost	$ (30)	[2]

[1] The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service 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 other postretirement benefit plans.

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Pension And Other Postretirement Benefits (Expected Contribution Pension Benefits And Other Postretirement Benefits) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2016	$ 2,000
Benefits payments expected in 2016	1,548
Benefits payments expected in 2017	1,491
Benefits payments expected in 2018	1,411
Benefits payments expected in 2019	1,382
Benefits payments expected in 2020	1,342
Benefits payments expected in 2021-2025	6,594
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2016	525
Benefits payments expected in 2016	1,145
Benefits payments expected in 2017	1,128
Benefits payments expected in 2018	1,178
Benefits payments expected in 2019	1,193
Benefits payments expected in 2020	1,227
Benefits payments expected in 2021-2025	6,359
Gross Other Post Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits payments expected in 2016	457
Benefits payments expected in 2017	470
Benefits payments expected in 2018	481
Benefits payments expected in 2019	490
Benefits payments expected in 2020	497
Benefits payments expected in 2021-2025	2,518
Other Postretirement Benefits Medicare Subsidy Receipt [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits payments expected in 2016	24
Benefits payments expected in 2017	25
Benefits payments expected in 2018	26
Benefits payments expected in 2019	28
Benefits payments expected in 2020	29
Benefit payments expected in 2021-2025	$ 170

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Disclosures About Segments And Related Information (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosures About Segments And Related Information [Abstract]
Non-debt-related interest expense	$ 100	$ 129	$ (123)

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Disclosures About Segments And Related Information (Schedule Of Segments And Related Information) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings after income tax		$ 16,150	$ 32,520	$ 32,580
Earnings of equity companies included above		7,644	13,323	13,927
Sales and other operating revenue	[1],[2]	259,488	394,105	420,836
Depreciation and depletion expense		18,048	17,297	17,182
Interest revenue		46	75	87
Interest expense		311	286	9
Income taxes		5,415	18,015	24,263
Additions to property, plant and equipment		27,475	34,256	37,741
Investments in equity companies		20,337	20,017	19,619
Total assets		336,758	349,493	346,808
U.S. [Member]
Income taxes		(1,140)	1,862	1,391
Non-U.S. [Member]
Income taxes		6,555	16,153	22,872
Upstream [Member] | U.S. [Member]
Earnings after income tax		(1,079)	5,197	4,191
Earnings of equity companies included above		226	1,235	1,576
Sales and other operating revenue	[2]	8,241	14,826	13,712
Intersegment revenue		4,344	7,723	8,343
Depreciation and depletion expense		5,301	5,139	5,170
Interest expense		26	40	30
Income taxes		(879)	1,300	2,197
Additions to property, plant and equipment		6,915	9,098	7,480
Investments in equity companies		5,160	5,089	4,975
Total assets		93,648	92,555	88,698
Upstream [Member] | Non-U.S. [Member]
Earnings after income tax		8,180	22,351	22,650
Earnings of equity companies included above		5,831	10,859	11,627
Sales and other operating revenue	[2]	15,812	22,336	25,349
Intersegment revenue		20,839	38,846	45,761
Depreciation and depletion expense		9,227	8,523	8,277
Interest expense		27	17	26
Income taxes		4,703	15,165	21,554
Additions to property, plant and equipment		14,561	19,225	26,075
Investments in equity companies		10,980	10,877	9,740
Total assets		155,316	161,033	157,465
Downstream [Member] | U.S. [Member]
Earnings after income tax		1,901	1,618	2,199
Earnings of equity companies included above		170	29	(460)
Sales and other operating revenue	[2]	73,063	118,771	123,802
Intersegment revenue		12,440	17,281	20,781
Depreciation and depletion expense		664	654	633
Interest expense		8	6	7
Income taxes		866	610	721
Additions to property, plant and equipment		916	1,050	616
Investments in equity companies		95	69	62
Total assets		16,498	18,371	19,261
Downstream [Member] | Non-U.S. [Member]
Earnings after income tax		4,656	1,427	1,250
Earnings of equity companies included above		444	82	22
Sales and other operating revenue	[2]	134,230	199,976	218,904
Intersegment revenue		22,166	44,231	52,624
Depreciation and depletion expense		1,003	1,228	1,390
Interest expense		4	4	8
Income taxes		1,325	968	481
Additions to property, plant and equipment		1,477	1,356	1,072
Investments in equity companies		1,179	1,006	1,749
Total assets		29,808	33,299	40,661
Chemical [Member] | U.S. [Member]
Earnings after income tax		2,386	2,804	2,755
Earnings of equity companies included above		144	186	189
Sales and other operating revenue	[2]	10,880	15,115	15,295
Intersegment revenue		7,442	10,117	11,993
Depreciation and depletion expense		375	370	378
Interest expense				1
Income taxes		646	1,032	989
Additions to property, plant and equipment		1,865	1,564	840
Investments in equity companies		125	258	217
Total assets		10,174	8,798	7,816
Chemical [Member] | Non-U.S. [Member]
Earnings after income tax		2,032	1,511	1,073
Earnings of equity companies included above		1,235	1,377	1,422
Sales and other operating revenue	[2]	17,254	23,063	23,753
Intersegment revenue		5,168	8,098	8,232
Depreciation and depletion expense		654	645	632
Interest expense		1
Income taxes		633	358	363
Additions to property, plant and equipment		629	564	272
Investments in equity companies		3,025	3,026	3,103
Total assets		18,236	18,449	19,659
Corporate And Financing [Member]
Earnings after income tax		(1,926)	(2,388)	(1,538)
Earnings of equity companies included above		(406)	(445)	(449)
Sales and other operating revenue	[2]	8	18	21
Intersegment revenue		274	274	285
Depreciation and depletion expense		824	738	702
Interest revenue		46	75	87
Interest expense		245	219	(63)
Income taxes		(1,879)	(1,418)	(2,042)
Additions to property, plant and equipment		1,112	1,399	1,386
Investments in equity companies		(227)	(308)	(227)
Total assets		$ 13,078	$ 16,988	$ 13,248

[1] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

[2] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

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Disclosures About Segments And Related Information (Schedule Of Geographic Sales And Other Operating Revenue) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	$ 259,488	$ 394,105	$ 420,836
Sales-based taxes	[2]	22,678	29,342	30,589
U.S. [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	92,184	148,713	152,820
Sales-based taxes		6,402	6,310	5,992
Non-U.S. [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	167,304	245,392	268,016
Sales-based taxes		16,276	23,032	24,597
United Kingdom [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	23,651	31,346	34,061
Canada [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	22,876	36,072	35,924
Italy [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	13,795	18,880	19,273
Belgium [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	13,154	20,953	20,973
France [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	11,808	17,639	18,444
Singapore [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	10,790	15,407	15,623
Germany [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	[1]	$ 10,045	$ 14,816	$ 15,701

[1] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

[2] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

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Disclosures About Segments And Related Information (Schedule Of Long-Lived Assets By Geographic Regions) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-lived assets	$ 251,605	$ 252,668	$ 243,650
U.S. [Member]
Long-lived assets	107,039	104,000	98,271
Non-U.S. [Member]
Long-lived assets	144,566	148,668	145,379
Canada [Member]
Long-lived assets	39,775	43,858	41,522
Australia [Member]
Long-lived assets	15,894	15,328	14,258
Nigeria [Member]
Long-lived assets	12,222	12,265	12,343
Kazakhstan [Member]
Long-lived assets	9,705	9,138	8,530
Singapore [Member]
Long-lived assets	9,681	9,620	9,570
Angola [Member]
Long-lived assets	8,777	9,057	8,262
Papua New Guinea [Member]
Long-lived assets	$ 5,985	$ 6,099	$ 5,768

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Income, Sales-Based And Other Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income, Sales-Based And Other Taxes [Abstract]
Net deferred income tax expense (credits)/charges for tax rate and law changes	$ 177,000,000	$ (40,000,000)	$ (310,000,000)
Reconciliation between income tax expense and theoretical U.S. tax rate, statutory rate	35.00%	35.00%	35.00%
Indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S.	$ 51,000,000,000
Potential percentage increase in unrecognized tax benefits	20.00%
Credit of net interest expense on income tax reserves			$ 207,000,000
Interest expense on income tax reserves	$ 39,000,000	$ 42,000,000
Interest payable on income tax reserves	223,000,000	205,000,000
Asset valuation allowances	1,730,000,000	$ 2,570,000,000
Valuation allowance change from 2014 to 2015	(840,000,000)
Change in net provisions [Member]
Valuation allowance change from 2014 to 2015	(681,000,000)
Effects of foreign currency translation [Member]
Valuation allowance change from 2014 to 2015	$ (159,000,000)

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Income, Sales-Based And Other Taxes (Schedule Of Income, Sales-Based And Other Taxes) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Income, Sales-Based and Other Taxes [Line Items]
Current		$ 7,126	$ 16,211		$ 23,188
Deferred - net		(1,737)	2,298		641
U.S. tax on non-U.S. operations		38	5		37
Total federal and non-U.S.		5,427	18,514		23,866
State		(12)	(499)	[1]	397
Total income tax expense		5,415	18,015		24,263
Sales-based taxes	[2]	22,678	29,342		30,589
Other taxes and duties		27,265	32,286		33,230
Other taxes and duties included in production and manufacturing expenses		1,985	2,633		2,500
Other taxes and duties included in SG&A expenses		540	596		666
Total other taxes and duties		29,790	35,515		36,396
Total		57,883	82,872		91,248
U.S. [Member]
Income, Sales-Based and Other Taxes [Line Items]
Current			1,456		1,073
Deferred - net		(1,166)	900		(116)
U.S. tax on non-U.S. operations		38	5		37
Total federal and non-U.S.		(1,128)	2,361		994
State		(12)	(499)	[1]	397
Total income tax expense		(1,140)	1,862		1,391
Sales-based taxes		6,402	6,310		5,992
Other taxes and duties		162	378		955
Other taxes and duties included in production and manufacturing expenses		1,157	1,454		1,318
Other taxes and duties included in SG&A expenses		150	155		150
Total other taxes and duties		1,469	1,987		2,423
Total		6,731	10,159		9,806
U.S. [Member] | State Tax Adjustment [Member]
Income, Sales-Based and Other Taxes [Line Items]
Deferred tax adjustment included in State Taxes			830
Non-U.S. [Member]
Income, Sales-Based and Other Taxes [Line Items]
Current		7,126	14,755		22,115
Deferred - net		(571)	1,398		757
Total federal and non-U.S.		6,555	16,153		22,872
Total income tax expense		6,555	16,153		22,872
Sales-based taxes		16,276	23,032		24,597
Other taxes and duties		27,103	31,908		32,275
Other taxes and duties included in production and manufacturing expenses		828	1,179		1,182
Other taxes and duties included in SG&A expenses		390	441		516
Total other taxes and duties		28,321	33,528		33,973
Total		$ 51,152	$ 72,713		$ 81,442

[1] In 2014, state taxes included a favorable adjustment of deferred taxes of approximately $830 million.

[2] Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

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Income, Sales-Based And Other Taxes (Reconciliation Between Income Tax Expense And Theoretical U.S. Tax) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income, Sales-Based And Other Taxes [Abstract]
United States income before income taxes	$ 147	$ 9,080	$ 9,746
Non-U.S. income before income taxes	21,819	42,550	47,965
Income before income taxes	21,966	51,630	57,711
Theoretical tax	7,688	18,071	20,199
Effect of equity method of accounting	(2,675)	(4,663)	(4,874)
Non-U.S. taxes in excess of theoretical U.S. tax	1,415	5,442	10,528
U.S. tax on non-U.S. operations	38	5	37
State taxes, net of federal tax benefit	(8)	(324)	258
Other	(1,043)	(516)	(1,885)
Total income tax expense	5,415	18,015	24,263
ExxonMobil share of equity company income taxes	3,011	5,678	6,061
Total income taxes	8,426	23,693	30,324
Net income including noncontrolling interests	16,551	33,615	33,448
Total income before taxes	$ 24,977	$ 57,308	$ 63,772
Effective income tax rate	34.00%	41.00%	48.00%

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Income, Sales-Based And Other Taxes (Deferred Income Taxes Assets And Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income, Sales-Based And Other Taxes [Abstract]
Property, plant and equipment	$ 49,409	$ 51,643
Other liabilities	4,613	4,359
Total deferred tax liabilities	54,022	56,002
Pension and other postretirement benefits	(6,286)	(8,140)
Asset retirement obligations	(6,277)	(6,162)
Tax loss carryforwards	(4,983)	(4,099)
Other assets	(5,592)	(6,446)
Total deferred tax assets	(23,138)	(24,847)
Asset valuation allowances	1,730	2,570
Net deferred tax liabilities	$ 32,614	$ 33,725

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Income, Sales-Based And Other Taxes (Deferred Income Tax (Assets) And Liabilities By Balance Sheet Classification) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income, Sales-Based And Other Taxes [Abstract]
Other current assets	$ (1,329)	$ (2,001)
Other assets, including intangibles, net	(3,421)	(3,955)
Accounts payable and accrued liabilities	546	451
Deferred income tax liabilities	36,818	39,230
Net deferred tax liabilities	$ 32,614	$ 33,725

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Income, Sales-Based And Other Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income, Sales-Based And Other Taxes [Abstract]
Balance at January 1	$ 8,986	$ 7,838	$ 7,663
Additions based on current year's tax positions	903	1,454	1,460
Additions for prior years' tax positions	496	448	464
Reductions for prior years' tax positions	(190)	(532)	(249)
Reductions due to lapse of the statute of limitations	(4)	(117)	(588)
Settlements with tax authorities	(725)	(43)	(849)
Foreign exchange effects/other	(70)	(62)	(63)
Balance at December 31	$ 9,396	$ 8,986	$ 7,838

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Income, Sales-Based And Other Taxes (Remaining Tax Years Subject To Examination By Major Tax Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2015
Abu Dhabi [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Abu Dhabi [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2012
Angola [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Angola [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2009
Australia First Range [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2005
Australia First Range [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2005
Australia Second Range [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Australia Second Range [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2008
Canada [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Canada [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2008
Equatorial Guinea [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Equatorial Guinea [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2007
Malaysia [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Malaysia [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2009
Nigeria [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Nigeria [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2005
Norway [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Norway [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2007
Qatar [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Qatar [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2009
Russia [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
Russia [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2012
United Kingdom [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
United Kingdom [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2011
United States [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2015
United States [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open tax years by major tax jurisdiction	2006