10-K

 

2014

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, 2014

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 (4,194,690,266 shares outstanding at January 31, 2015)	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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $100.68 on the New York Stock Exchange composite tape, was in excess of $429 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2015 Annual Meeting of Shareholders (Part III)

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014

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		113
Index to Exhibits		115
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 2014 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $6.2 billion, of which $3.5 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to remain in this range in 2015 and 2016 (with capital expenditures approximately 40 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 2014. For technology licensed to third parties, revenues totaled approximately $148 million in 2014. 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 75.3 thousand, 75.0 thousand, and 76.9 thousand at years ended 2014, 2013 and 2012, 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 8.4 thousand, 9.8 thousand, and 11.1 thousand at years ended 2014, 2013 and 2012, respectively.

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.

1

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.

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 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.

2

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 on schedule 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.

3

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.

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 ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our rigorous disaster preparedness and response planning, as well as business continuity planning.

Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of this 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.

4

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 2014

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2014, 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		1,215	287	-	-	14,169	3,864
			Canada/South America (1)		98	13	2,122	534	615	2,869
			Europe		170	35	-	-	1,870	517
			Africa		722	172	-	-	764	1,021
			Asia		1,481	134	-	-	5,031	2,453
			Australia/Oceania		74	38	-	-	2,179	475
				Total Consolidated	3,760	679	2,122	534	24,628	11,199
		Equity Companies
			United States		259	10	-	-	194	301
			Europe		26	-	-	-	6,484	1,107
			Asia		822	366	-	-	16,305	3,906
				Total Equity Company	1,107	376	-	-	22,983	5,314
				Total Developed	4,867	1,055	2,122	534	47,611	16,513
	Undeveloped
		Consolidated Subsidiaries
			United States		893	341	-	-	11,818	3,203
			Canada/South America (1)		184	6	2,111	-	611	2,403
			Europe		29	13	-	-	513	127
			Africa		380	21	-	-	47	409
			Asia		651	-	-	-	429	723
			Australia/Oceania		67	32	-	-	5,097	949
				Total Consolidated	2,204	413	2,111	-	18,515	7,814
		Equity Companies
			United States		69	6	-	-	78	88
			Europe		1	-	-	-	1,934	323
			Asia		278	53	-	-	1,200	531
				Total Equity Company	348	59	-	-	3,212	942
				Total Undeveloped	2,552	472	2,111	-	21,727	8,756
Total Proved Reserves					7,419	1,527	4,233	534	69,338	25,269

(1)   South America includes proved developed reserves of 0.2 million barrels of crude oil and natural gas liquids and 39 billion cubic feet of natural gas and proved undeveloped reserves of 7 billion cubic feet of natural gas.

5

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

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 gas price levels.

B. Technologies Used in Establishing Proved Reserves Additions in 2014

Additions to ExxonMobil’s proved reserves in 2014 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 managed by and 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 members have served on the SPE Oil and Gas Reserves Committee.

The Global Reserves group maintains a central database containing the official company reserves estimates. Appropriate controls, including 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.

6

2. Proved Undeveloped Reserves

At year-end 2014, approximately 8.8 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 35 percent of the 25.3 GOEB reported in proved reserves. This compares to the 8.5 GOEB of proved undeveloped reserves reported at the end of 2013. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 0.8 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to Papua New Guinea (PNG) LNG start-up and drilling activity in the United States.

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 2014, discoveries and extensions related to new projects added approximately 0.6 GOEB of proved undeveloped reserves. The largest of these additions were related to planned drilling in the United States and project funding in Angola, Russia and Kazakhstan. Overall, investments of $24.2 billion were made by the Corporation during 2014 to progress the development of reported proved undeveloped reserves, including $22.4 billion for oil and gas producing activities and an additional $1.8 billion for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 74 percent of the $32.7 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Australia, the United States, Kazakhstan, Nigeria, and the Netherlands 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 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 reported that are 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.

				2014		2013		2012
				(thousands of barrels daily)
Crude oil and natural gas liquids production				Crude Oil	NGL	Crude Oil	NGL	Crude Oil	NGL
	Consolidated Subsidiaries
		United States		304	85	283	85	274	81
		Canada/South America (1)		52	9	57	10	49	10
		Europe		151	28	157	27	170	33
		Africa		469	20	451	18	472	15
		Asia		293	26	313	30	319	43
		Australia/Oceania		39	20	29	19	32	18
			Total Consolidated Subsidiaries	1,308	188	1,290	189	1,316	200
	Equity Companies
		United States		63	2	61	2	61	2
		Europe		5	-	6	-	4	-
		Asia		236	69	373	68	345	65
			Total Equity Companies	304	71	440	70	410	67
Total crude oil and natural gas liquids production				1,612	259	1,730	259	1,726	267
Bitumen production
	Consolidated Subsidiaries
		Canada/South America		180		148		123
Synthetic oil production
	Consolidated Subsidiaries
		Canada/South America		60		65		69
Total liquids production				2,111		2,202		2,185
				(millions of cubic feet daily)
Natural gas production available for sale
	Consolidated Subsidiaries
		United States		3,374		3,530		3,819
		Canada/South America (1)		310		354		362
		Europe		1,226		1,294		1,446
		Africa		4		6		17
		Asia		1,067		1,180		1,445
		Australia/Oceania		512		351		363
			Total Consolidated Subsidiaries	6,493		6,715		7,452
	Equity Companies
		United States		30		15		3
		Europe		1,590		1,957		1,774
		Asia		3,032		3,149		3,093
			Total Equity Companies	4,652		5,121		4,870
Total natural gas production available for sale				11,145		11,836		12,322
				(thousands of oil-equivalent barrels daily)
Oil-equivalent production				3,969		4,175		4,239

(1)   South America includes liquids production for 2012 of one thousand barrels daily and natural gas production available for sale for 2014, 2013 and 2012 of 21 million, 28 million, and 38 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 2014				(dollars per unit)
	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
During 2013
	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

9

				United		Canada/				Australia/
				States	S. America		Europe	Africa	Asia		Oceania	Total
During 2012				(dollars per unit)
	Consolidated Subsidiaries
		Average production prices
			Crude oil, per barrel	94.71		98.67	110.91	111.19	109.95		112.12	107.05
			NGL, per barrel	50.32		57.84	68.08	76.63	43.65		56.85	54.71
			Natural gas, per thousand cubic feet	2.15		1.98	8.92	2.77	3.91		4.39	3.90
			Bitumen, per barrel	-		58.91	-	-	-		-	58.91
			Synthetic oil, per barrel	-		92.77	-	-	-		-	92.77
		Average production costs, per oil-equivalent barrel - total		11.14		26.94	15.06	13.35	7.27		12.11	13.02
		Average production costs, per barrel - bitumen		-		23.71	-	-	-		-	23.71
		Average production costs, per barrel - synthetic oil		-		47.45	-	-	-		-	47.45
	Equity Companies
		Average production prices
			Crude oil, per barrel	105.02		-	104.59	-	106.59		-	106.33
			NGL, per barrel	58.38		-	-	-	75.24		-	74.87
			Natural gas, per thousand cubic feet	3.22		-	9.66	-	9.38		-	9.48
		Average production costs, per oil-equivalent barrel - total		20.15		-	3.36	-	1.43		-	2.80
	Total
		Average production prices
			Crude oil, per barrel	96.60		98.67	110.74	111.19	108.22		112.12	106.88
			NGL, per barrel	50.46		57.84	68.08	76.63	62.61		56.85	59.74
			Natural gas, per thousand cubic feet	2.15		1.98	9.33	2.77	7.64		4.39	6.11
			Bitumen, per barrel	-		58.91	-	-	-		-	58.91
			Synthetic oil, per barrel	-		92.77	-	-	-		-	92.77
		Average production costs, per oil-equivalent barrel - total		11.68		26.94	10.34	13.35	3.74		12.11	9.91
		Average production costs, per barrel - bitumen		-		23.71	-	-	-		-	23.71
		Average production costs, per barrel - synthetic oil		-		47.45	-	-	-		-	47.45

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.

10

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled

				2014	2013	2012
Net Productive Exploratory Wells Drilled
	Consolidated Subsidiaries
		United States		3	8	7
		Canada/South America		3	4	2
		Europe		1	-	1
		Africa		2	2	2
		Asia		-	-	1
		Australia/Oceania		-	-	2
			Total Consolidated Subsidiaries	9	14	15
	Equity Companies
		United States		-	-	-
		Europe		2	1	1
		Asia		-	1	-
			Total Equity Companies	2	2	1
Total productive exploratory wells drilled				11	16	16
Net Dry Exploratory Wells Drilled
	Consolidated Subsidiaries
		United States		2	2	2
		Canada/South America		1	4	-
		Europe		1	1	2
		Africa		1	-	-
		Asia		-	-	2
		Australia/Oceania		-	-	1
			Total Consolidated Subsidiaries	5	7	7
	Equity Companies
		United States		2	1	-
		Europe		-	-	1
		Asia		-	-	-
			Total Equity Companies	2	1	1
Total dry exploratory wells drilled				7	8	8

11

				2014	2013	2012
Net Productive Development Wells Drilled
	Consolidated Subsidiaries
		United States		721	755	867
		Canada/South America		178	201	73
		Europe		8	13	10
		Africa		41	33	39
		Asia		19	30	28
		Australia/Oceania		5	3	-
			Total Consolidated Subsidiaries	972	1,035	1,017
	Equity Companies
		United States		340	328	282
		Europe		2	2	4
		Asia		1	8	7
			Total Equity Companies	343	338	293
Total productive development wells drilled				1,315	1,373	1,310
Net Dry Development Wells Drilled
	Consolidated Subsidiaries
		United States		6	5	5
		Canada/South America		3	-	-
		Europe		1	2	1
		Africa		-	-	-
		Asia		-	-	2
		Australia/Oceania		-	-	-
			Total Consolidated Subsidiaries	10	7	8
	Equity Companies
		United States		-	-	-
		Europe		1	1	-
		Asia		-	-	-
			Total Equity Companies	1	1	-
Total dry development wells drilled				11	8	8
	Total number of net wells drilled			1,344	1,405	1,342

12

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 2014, the company’s share of net production of synthetic crude oil was about 60 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project. The Kearl project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the 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 about 48 thousand acres in the Athabasca oil sands deposit.

The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment train. 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. During 2014, average net production at Kearl was 66 thousand barrels per day. The Kearl Expansion project was essentially complete at the end of 2014, and the commissioning of facilities commenced in preparation for start-up.

5. Present Activities

A. Wells Drilling

				Year-End 2014		Year-End 2013
				Gross	Net	Gross	Net
Wells Drilling
	Consolidated Subsidiaries
		United States		1,120	442	1,199	480
		Canada/South America		35	29	107	95
		Europe		18	8	29	10
		Africa		33	12	38	11
		Asia		90	26	112	32
		Australia/Oceania		10	4	18	5
			Total Consolidated Subsidiaries	1,306	521	1,503	633
	Equity Companies
		United States		31	6	9	4
		Europe		4	1	8	3
		Asia		1	-	11	1
			Total Equity Companies	36	7	28	8
Total gross and net wells drilling				1,342	528	1,531	641

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2014 acreage holdings totaled 14.6 million net acres, of which 1.7 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During the year, 1,048.3 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, the Bakken oil play in North Dakota and Montana, and the Woodford and Caney Shales in the Ardmore and Marietta basins of Oklahoma. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia, the Utica Shale of Ohio, the Haynesville Shale of Texas and Louisiana, the Barnett Shale of North Texas, and the Fayetteville Shale of Arkansas.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2014 was 1.5 million acres. A total of 2.6net exploration and development wells were completed during the year. Development activities were completed on the deepwater Hadrian South project and the non-operated Lucius project. ExxonMobil continued development activities on the Heidelberg and Julia Phase 1 projects. Offshore California 5.0 net development wells were completed.

13

Participation in Alaska production and development continued with a total of 18.3 net development wells completed. Development activities continued on the Point Thomson project.

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations:ExxonMobil’s year-end 2014 acreage holdings totaled 5.4 million net acres, of which 1.0 million net acres were offshore. A total of 89.2 net development wells were completed during the year.

In Situ Bitumen Operations:ExxonMobil’s year-end 2014 in situ bitumen acreage holdings totaled 0.7 million net onshore acres. A total of 90.0 net development wells were completed during the year.

Argentina

ExxonMobil’s net acreage totaled 0.9 million onshore acres at year-end 2014, and there were 4.6 net exploration and development wells completed during the year.

EUROPE

Germany

A total of 4.9 million net onshore acres were held by ExxonMobil at year-end 2014, with 2.6 net exploration and development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2014, of which 1.2 million acres were onshore. A total of 5.1 net exploration and development wells were completed during the year.

Norway

ExxonMobil’s net interest in licenses at year-end 2014 totaled approximately 0.4 million acres, all offshore. A total of 4.9 net exploration and development wells were completed in 2014.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2014 totaled approximately 0.6 million acres, all offshore. A total of 2.1 net development wells were completed during the year.

AFRICA

Angola

ExxonMobil’s net acreage totaled 0.4 million offshore acres at year-end 2014, with 6.7 net exploration and development wells completed during the year. On Block 15, development activities continued at Kizomba Satellites Phase 2. The Kaombo project on Block 32 was funded in 2014. The Cravo-Lirio-Orquidea-Violeta project, on the non-operated Block 17, started up in 2014.

Chad

ExxonMobil’s net year-end 2014 acreage holdings consisted of 46 thousand onshore acres, with 30.0 net development wells completed during the year.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2014, with 1.5 net development wells completed during the year.

Nigeria

ExxonMobil’s net acreage totaled 0.8 million offshore acres at year-end 2014, with 3.6 net exploration and development wells completed during the year. In 2014, ExxonMobil continued development drilling on the deepwater Usan and Erha North Phase 2 projects. Satellite Field Development Phase 1 development drilling was completed, and the Bonga Northwest deepwater project started up in 2014.

14

ASIA

Azerbaijan

At year-end 2014, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.9 net development wells were completed during the year. The Chirag Oil project was completed, and the sixth producing platform, West Chirag, started up in 2014.

Indonesia

At year-end 2014, ExxonMobil had 1.7 million net acres, 1.3 million net acres offshore and 0.4 million net acres onshore, with 7.7 net development wells completed during the year.

Iraq

At year-end 2014, ExxonMobil’s onshore acreage was 0.7 million net acres. A total of 3.0 net development wells were completed at the West Qurna Phase I oil field during the year. Field rehabilitation activities continued during 2014 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, ExxonMobil continued its seismic program and exploration drilling until operations were temporarily suspended due to security concerns in the region.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2014. A total of 1.2 net development wells were completed during 2014. 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 2014. During the year, a total of 4.5 net development wells were completed. The Tapis Enhanced Oil Recovery and Damar projects started up in 2014.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2014. During the year, a total of 0.3 net development wells were completed. ExxonMobil participated in 61.8 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 2014.

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2014 were 85 thousand acres, all offshore. A total of 1.2 net development wells were completed. Development activities continued on the Arkutun-Dagi project, and the Odoptu Stage 2 project was funded in 2014.

At year-end 2014, 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 2014.

15

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2014. During the year, a total of 1.7 net development wells were completed. Development activities continued on the Upper Zakum 750 project.

ExxonMobil’s onshore oil concession expired in January 2014.

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2014 acreage holdings totaled 1.7 million net acres, of which 1.6 million net acres were offshore. During the year, a total of 3.8 net exploration and development wells were completed. Construction activities continued on the Gas Conditioning Plant at Longford.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2014. 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 2014, with 1.6 net development wells completed during the year. The Papua New Guinea (PNG) LNG project started up in 2014. The PNG LNG integrated development includes gas production and processing facilities in the southern PNG Highlands, a 6.9 million tonnes per yearLNG facility near Port Moresby and approximately 434 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2014, 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 33.4 million net acres were held at year-end 2014 and 3.8net 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 18 million barrels of oil and 2,800 billion cubic feet of natural gas for the period from 2015 through 2017. 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.

16

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

A. Gross and Net Productive Wells

				Year-End 2014				Year-End 2013
				Oil		Gas		Oil		Gas
				Gross	Net	Gross	Net	Gross	Net	Gross	Net
Gross and Net Productive Wells
	Consolidated Subsidiaries
		United States		24,242	9,249	36,095	21,571	23,395	8,487	38,392	23,839
		Canada/South America		5,012	4,659	4,577	1,782	5,486	4,990	4,478	1,762
		Europe		1,215	347	642	259	1,254	352	649	269
		Africa		1,299	513	19	8	1,186	472	16	6
		Asia		804	267	207	150	756	270	207	151
		Australia/Oceania		669	157	43	21	661	147	38	19
			Total Consolidated Subsidiaries	33,241	15,192	41,583	23,791	32,738	14,718	43,780	26,046
	Equity Companies
		United States		14,571	5,605	4,365	494	14,362	5,529	4,369	496
		Europe		57	20	567	179	49	17	555	173
		Asia		110	27	125	30	1,329	143	122	29
			Total Equity Companies	14,738	5,652	5,057	703	15,740	5,689	5,046	698
Total gross and net productive wells				47,979	20,844	46,640	24,494	48,478	20,407	48,826	26,744

There were 35,446 gross and 29,870 net operated wells at year-end 2014 and 37,661 gross and 31,823 net operated wells at year-end 2013. The number of wells with multiple completions was 1,219 gross in 2014 and 1,531 gross in 2013.

.

17

B. Gross and Net Developed Acreage

				Year-End 2014		Year-End 2013
				Gross	Net	Gross	Net
				(thousands of acres)
Gross and Net Developed Acreage
	Consolidated Subsidiaries
		United States		14,777	9,367	16,504	10,061
		Canada/South America (1)		3,515	2,242	3,413	2,041
		Europe		3,337	1,506	3,355	1,511
		Africa		2,286	815	2,105	780
		Asia		1,817	551	1,828	557
		Australia/Oceania		2,123	758	2,123	758
			Total Consolidated Subsidiaries	27,855	15,239	29,328	15,708
	Equity Companies
		United States		949	208	968	241
		Europe		4,342	1,356	4,341	1,356
		Asia		628	156	5,731	640
			Total Equity Companies	5,919	1,720	11,040	2,237
Total gross and net developed acreage				33,774	16,959	40,368	17,945

(1)   Includes developed acreage in South America of 213 gross and 109 net thousands of acres for 2014 and 214 gross and 109 net thousands of acres for 2013.

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 2014		Year-End 2013
				Gross	Net	Gross	Net
				(thousands of acres)
Gross and Net Undeveloped Acreage
	Consolidated Subsidiaries
		United States		10,262	4,894	7,645	4,722
		Canada/South America (1)		16,100	12,250	16,267	9,232
		Europe		10,601	5,636	13,461	6,585
		Africa		22,143	15,020	20,877	13,446
		Asia		17,437	13,016	18,639	13,979
		Australia/Oceania		6,653	2,013	7,144	1,991
			Total Consolidated Subsidiaries	83,196	52,829	84,033	49,955
	Equity Companies
		United States		350	118	363	121
		Europe		-	-	-	-
		Asia		191,146	63,632	34,147	11,352
			Total Equity Companies	191,496	63,750	34,510	11,473
Total gross and net undeveloped acreage				274,692	116,579	118,543	61,428

(1)   Includes undeveloped acreage in South America of 9,056 gross and 8,083 net thousands of acres for 2014 and 8,795 gross and 4,674 net thousands of acres for 2013.

Note:  Year-end 2013 gross developed and undeveloped acreage in Canada/South America was restated.

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.

18

D. Summary of Acreage Terms

UNITED STATES

Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, 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.

19

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 at the discretion of the government.

Equatorial Guinea

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for 10 to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years, while the production period for gas is 50 years. Under the Hydrocarbons Law enacted in 2006, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.

Nigeria

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC 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 negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years with the possibility of two-year extensions. 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 date of the execution of the contract and the date of first commercial lifting.

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.

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

Exploration and production activities for the major onshore oil fields in the Emirate of Abu Dhabi were governed by a 75-year oil concession agreement executed in 1939, which expired in January 2014. 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 2014 (1)

				ExxonMobil	ExxonMobil
				Share  KBD (2)	Interest %
United States
	Torrance		California	150	100
	Joliet		Illinois	238	100
	Baton Rouge		Louisiana	502	100
	Baytown		Texas	561	100
	Beaumont		Texas	345	100
	Other (2 refineries)			155
		Total United States		1,951
Canada
	Strathcona		Alberta	189	69.6
	Nanticoke		Ontario	113	69.6
	Sarnia		Ontario	119	69.6
		Total Canada		421
Europe
	Antwerp		Belgium	307	100
	Fos-sur-Mer		France	133	82.9
	Gravenchon		France	236	82.9
	Karlsruhe		Germany	78	25
	Augusta		Italy	198	100
	Trecate		Italy	127	74.9
	Rotterdam		Netherlands	191	100
	Slagen		Norway	116	100
	Fawley		United Kingdom	260	100
		Total Europe		1,646
Asia Pacific
	Jurong/PAC		Singapore	592	100
	Sriracha		Thailand	167	66
	Other (7 refineries)			256
		Total Asia Pacific		1,015
Other Non-U.S.
	Yanbu		Saudi Arabia	200	50
	Laffan		Qatar	15	10
		Total Other Non-U.S.		215
Total Worldwide				5,248

(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.

(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 2014

United States
	Owned/leased		-
	Distributors/resellers		9,436
		Total United States	9,436
Canada
	Owned/leased		473
	Distributors/resellers		1,256
		Total Canada	1,729
Europe
	Owned/leased		3,209
	Distributors/resellers		3,049
		Total Europe	6,258
Asia Pacific
	Owned/leased		653
	Distributors/resellers		757
		Total Asia Pacific	1,410
Latin America
	Owned/leased		15
	Distributors/resellers		734
		Total Latin America	749
Middle East/Africa
	Owned/leased		404
	Distributors/resellers		231
		Total Middle East/Africa	635
Worldwide
	Owned/leased		4,754
	Distributors/resellers		15,463
		Total Worldwide	20,217

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 2014 (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	0.6	100
	Beaumont		Texas	0.9	1.0	-	0.3	100
	Mont Belvieu		Texas	-	1.0	-	-	100
	Sarnia		Ontario	0.3	0.5	-	-	69.6
		Total North America		4.4	3.8	1.1	0.9
Europe
	Antwerp		Belgium	-	0.4	-	-	100
	Fife		United Kingdom	0.4	-	-	-	50
	Meerhout		Belgium	-	0.5	-	-	100
	Gravenchon		France	0.4	0.4	0.3	-	100
	Rotterdam		Netherlands	-	-	-	0.7	100
		Total Europe		0.8	1.3	0.3	0.7
Middle East
	Al Jubail		Saudi Arabia	0.6	0.7	-	-	50
	Yanbu		Saudi Arabia	1.0	0.7	0.2	-	50
		Total Middle East		1.6	1.4	0.2	-
Asia Pacific
	Fujian		China	0.3	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
All Other				-	-	-	0.1
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.

25

Item 3.       Legal Proceedings

Regarding the discussions between Chalmette Refining LLC (CRLLC), owner of the Chalmette Refinery (operated by ExxonMobil Oil Corporation), and the Louisiana Department of Environmental Quality (LDEQ) to resolve self-reported deviations from refinery operations and relating to certain Clean Air Act Title V permit conditions, limits and other requirements reported in the Corporation’s Form 10-Q for the second quarter of 2012, on November 14, 2014, CRLLC received a Consolidated Compliance Order and Notice of Potential Penalty (CCO/NOPP) from LDEQ covering the deviations between 2009 and 2010. CRLLC and LDEQ have entered a dispute resolution agreement, which suspends enforcement of the CCO/NOPP while negotiations are ongoing.

Regarding allegations raised by LDEQ concerning the April 28, 2012, discharge of crude oil from the ExxonMobil Pipeline Company’s (EMPCo) North Line Pipeline near Torbert in Pointe Coupee Parish, Louisiana, previously reported in the Corporation’s Forms 10-Q for the third quarter of 2013 and the third quarter of 2014, on December 9, 2014, LDEQ notified EMPCo that it was seeking a Penalty Assessment of $471,000 related to the discharge. EMPCo has timely requested an adjudicatory hearing on disputed issues of fact and law related to the proposed penalty assessment.

With respect to the enforcement action filed by the United States, on behalf of the United States Environmental Protection Agency (USEPA), and the State of Arkansas, on behalf of the Arkansas Department of Environmental Quality, against EMPCo related to the discharge of crude oil from the Pegasus Pipeline in Mayflower, Faulkner County, Arkansas, previously reported in the Corporation’s Forms 10-Q for the first, second and third quarters of 2013 and the first and second quarters of 2014, a motion has been filed to extend an earlier court approved stay of discovery to allow the parties to pursue settlement discussions.

Regarding the $1.7 million penalty assessment against EMPCo by the U.S. Department of Transportation Pipeline & Hazardous Materials Safety Administration (PHMSA) for alleged violations of the federal Pipeline Safety Regulations in connection with the July 1, 2011, discharge of crude oil into the Yellowstone River from EMPCo’s Silvertip Pipeline near Laurel, Montana, reported in the Corporation’s Forms 10-Q for the first and second quarters of 2013 and the second quarter of 2014, following a 2013 administrative hearing requested by EMPCo to contest PHMSA allegations and the proposed penalty, on January 23, 2015, PHMSA announced a final order reducing the penalty to $1.05 million. On February 12, 2015, EMPCo filed a motion for reconsideration of the final order.

With respect to the administrative orders alleging Clean Water Act violations issued by the USEPA with regard to three locations of XTO Energy, Inc. (XTO) in West Virginia and the five unresolved additional West Virginia sites voluntarily disclosed by XTO to the USEPA reported in the Corporation’s Forms 10-Q for the first quarter of 2012 and the first three quarters of 2014, in December 2014, XTO agreed to a settlement with the Department of Justice, USEPA and West Virginia Department of Environmental Protections (WVDEP) pursuant to which XTO would pay a civil penalty of $2.3 million and enter into a Consent Decree with the Department of Justice, USEPA and WVDEP. The Consent Decree requires XTO to prepare and submit restoration plans for approval by USEPA and WVDEP and conduct approximately $3.0 million in restoration and mitigation activities at the impacted locations or at alternative locations approved by the USEPA and WVDEP. The Consent Decree is subject to Court approval. On January 6, 2015, the Justice Department published a notice in the Federal Register stating that the Consent Decree had been lodged with the Court and soliciting public comment for a period of 30 days.

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: 62
Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the Board and Chief Executive Officer on January 1, 2006. He still holds these positions as of this filing date.

Mark W. Albers	Senior Vice President
Held current title since:	April 1, 2007	Age: 58
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: 61
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: 58
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: 51
Mr. Jack P. Williams, Jr. was Vice President of ExxonMobil Development Company May 1, 2009 – July 1, 2010. He 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.

Darren W. Woods	Senior Vice President
Held current title since:	June 1, 2014	Age: 50
Mr. Darren W. Woods was Director, Refining Europe/Africa/Middle East, ExxonMobil Refining & Supply Company     February 1, 2008 – June 30, 2010. He 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 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: 63
Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 – March 1, 2010. He 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: 52
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: 53
Mr. Randy J. Cleveland was Planning & Commercial Manager, ExxonMobil Production Company May 1, 2009 – June 24, 2010. He 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: 61
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.

Michael G. Cousins	Vice President
Held current title since:	March 1, 2013	Age: 54
Mr. Michael G. Cousins was Vice President, Asia Pacific/Middle East, ExxonMobil Exploration Company June 1, 2009 – March 31, 2012. He was Executive Assistant to the Chairman, Exxon Mobil Corporation April 1, 2012 – February 28, 2013.  He became President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date.

Neil W. Duffin	President, ExxonMobil Development Company
Held current title since:	April 13, 2007	Age: 58
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: 57
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: 57
Mr. Stephen M. Greenlee was President of ExxonMobil Upstream Research Company June 1, 2009 – August 31, 2010. He 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.

28

Alan J. Kelly	Vice President
Held current title since:	December 1, 2007	Age: 57
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.

David S. Rosenthal	Vice President and Controller
Held current title since:	October 1, 2008 (Vice President) September 1, 2014 (Controller)	Age: 58
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: 58
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: 53
Mr. James M. Spellings, Jr. was Associate General Tax Counsel of Exxon Mobil Corporation April 1, 2007 – March 1, 2010. He 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: 60
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: 58
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: 54
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, 2014
				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 2014		11,934,362	93.06	11,934,362
November 2014		9,803,071	95.42	9,803,071
December 2014		13,899,727	91.55	13,899,727
	Total	35,637,160	93.12	35,637,160	(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, 2015, the Corporation stated that first quarter 2015 share purchases to reduce shares outstanding are anticipated to equal $1 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

Item 6.       Selected Financial Data

	Years Ended December 31,
	2014	2013	2012	2011	2010
	(millions of dollars, except per share amounts)
Sales and other operating revenue (1)	394,105	420,836	451,509	467,029	370,125
(1) Sales-based taxes included	29,342	30,589	32,409	33,503	28,547
Net income attributable to ExxonMobil	32,520	32,580	44,880	41,060	30,460
Earnings per common share	7.60	7.37	9.70	8.43	6.24
Earnings per common share - assuming dilution	7.60	7.37	9.70	8.42	6.22
Cash dividends per common share	2.70	2.46	2.18	1.85	1.74
Total assets	349,493	346,808	333,795	331,052	302,510
Long-term debt	11,653	6,891	7,928	9,322	12,227

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 25, 2015, 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, 2014. 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, 2014.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014, 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 2015 annual meeting of shareholders (the “2015 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 2015 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 2015 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		24,243,615	(1)	-	109,066,057	(2)(3)
Equity compensation plans not approved by security holders		-		-	-
	Total	24,243,615		-	109,066,057

(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 108,454,857 shares available for award under the 2003 Incentive Program and 611,200 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 2015 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 2015 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	41
Overview	41
Business Environment and Risk Assessment	41
Review of 2014 and 2013 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	60
Report of Independent Registered Public Accounting Firm	61
Consolidated Financial Statements
Statement of Income	62
Statement of Comprehensive Income	63
Balance Sheet	64
Statement of Cash Flows	65
Statement of Changes in Equity	66
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies	67
2. Accounting Changes	69
3. Miscellaneous Financial Information	69
4. Other Comprehensive Income Information	70
5. Cash Flow Information	71
6. Additional Working Capital Information	71
7. Equity Company Information	72
8. Investments, Advances and Long-Term Receivables	73
9. Property, Plant and Equipment and Asset Retirement Obligations	74
10. Accounting for Suspended Exploratory Well Costs	75
11. Leased Facilities	77
12. Earnings Per Share	77
13. Financial Instruments and Derivatives	78
14. Long-Term Debt	79
15. Incentive Program	80
16. Litigation and Other Contingencies	81
17. Pension and Other Postretirement Benefits	83
18. Disclosures about Segments and Related Information	91
19. Income, Sales-Based and Other Taxes	94
Supplemental Information on Oil and Gas Exploration and Production Activities	97
Operating Summary	112

34

BUSINESS PROFILE

							Return on			Capital and
			Earnings After		Average Capital		Average Capital			Exploration
			Income Taxes		Employed		Employed			Expenditures
Financial			2014	2013	2014	2013	2014	2013		2014	2013
			(millions of dollars)				(percent)		(millions of dollars)
Upstream
	United States		5,197	4,191	62,403	59,898	8.3	7.0		9,401	9,145
	Non-U.S.		22,351	22,650	102,562	93,071	21.8	24.3		23,326	29,086
		Total	27,548	26,841	164,965	152,969	16.7	17.5		32,727	38,231
Downstream
	United States		1,618	2,199	6,070	4,757	26.7	46.2		1,310	951
	Non-U.S.		1,427	1,250	17,907	19,673	8.0	6.4		1,724	1,462
		Total	3,045	3,449	23,977	24,430	12.7	14.1		3,034	2,413
Chemical
	United States		2,804	2,755	6,121	4,872	45.8	56.5		1,690	963
	Non-U.S.		1,511	1,073	16,076	15,793	9.4	6.8		1,051	869
		Total	4,315	3,828	22,197	20,665	19.4	18.5		2,741	1,832
Corporate and financing			(2,388)	(1,538)	(8,029)	(6,489)	-	-		35	13
		Total	32,520	32,580	203,110	191,575	16.2	17.2		38,537	42,489

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

Operating			2014	2013				2014	2013
		(thousands of barrels daily)					(thousands of barrels daily)
Net liquids production					Refinery throughput
	United States		454	431		United States		1,809	1,819
	Non-U.S.		1,657	1,771		Non-U.S.		2,667	2,766
		Total	2,111	2,202			Total	4,476	4,585
		(millions of cubic feet daily)					(thousands of barrels daily)
Natural gas production available for sale					Petroleum product sales
	United States		3,404	3,545		United States		2,655	2,609
	Non-U.S.		7,741	8,291		Non-U.S.		3,220	3,278
		Total	11,145	11,836			Total	5,875	5,887
		(thousands of oil-equivalent barrels daily)					(thousands of metric tons)
Oil-equivalent production (1)			3,969	4,175	Chemical prime product sales (2)
						United States		9,528	9,679
						Non-U.S.		14,707	14,384
							Total	24,235	24,063

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

(2)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

			2014	2013	2012	2011	2010
		(millions of dollars, except per share amounts)
Sales and other operating revenue (1)			394,105	420,836	451,509	467,029	370,125
Earnings
	Upstream		27,548	26,841	29,895	34,439	24,097
	Downstream		3,045	3,449	13,190	4,459	3,567
	Chemical		4,315	3,828	3,898	4,383	4,913
	Corporate and financing		(2,388)	(1,538)	(2,103)	(2,221)	(2,117)
	Net income attributable to ExxonMobil		32,520	32,580	44,880	41,060	30,460
Earnings per common share			7.60	7.37	9.70	8.43	6.24
Earnings per common share – assuming dilution			7.60	7.37	9.70	8.42	6.22
Cash dividends per common share			2.70	2.46	2.18	1.85	1.74
Earnings to average ExxonMobil share of equity (percent)			18.7	19.2	28.0	27.3	23.7
Working capital			(11,723)	(12,416)	321	(4,542)	(3,649)
Ratio of current assets to current liabilities (times)			0.82	0.83	1.01	0.94	0.94
Additions to property, plant and equipment			34,256	37,741	35,179	33,638	74,156
Property, plant and equipment, less allowances			252,668	243,650	226,949	214,664	199,548
Total assets			349,493	346,808	333,795	331,052	302,510
Exploration expenses, including dry holes			1,669	1,976	1,840	2,081	2,144
Research and development costs			971	1,044	1,042	1,044	1,012
Long-term debt			11,653	6,891	7,928	9,322	12,227
Total debt			29,121	22,699	11,581	17,033	15,014
Fixed-charge coverage ratio (times)			46.9	55.7	62.4	53.4	42.2
Debt to capital (percent)			13.9	11.2	6.3	9.6	9.0
Net debt to capital (percent) (2)			11.9	9.1	1.2	2.6	4.5
ExxonMobil share of equity at year-end			174,399	174,003	165,863	154,396	146,839
ExxonMobil share of equity per common share			41.51	40.14	36.84	32.61	29.48
Weighted average number of common shares
	outstanding (millions)		4,282	4,419	4,628	4,870	4,885
Number of regular employees at year-end (thousands) (3)			75.3	75.0	76.9	82.1	83.6
CORS employees not included above (thousands) (4)			8.4	9.8	11.1	17.0	20.1

(1)   Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013, $32,409 million for 2012, $33,503 million for 2011 and $28,547 million for 2010.

(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		2014	2013	2012
		(millions of dollars)
Net cash provided by operating activities		45,116	44,914	56,170
Proceeds associated with sales of subsidiaries, property, plant and equipment,
	and sales and returns of investments	4,035	2,707	7,655
	Cash flow from operations and asset sales	49,151	47,621	63,825

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		2014	2013	2012
		(millions of dollars)
Business uses: asset and liability perspective
Total assets		349,493	346,808	333,795
Less liabilities and noncontrolling interests share of assets and liabilities
	Total current liabilities excluding notes and loans payable	(47,165)	(55,916)	(60,486)
	Total long-term liabilities excluding long-term debt	(92,143)	(87,698)	(90,068)
	Noncontrolling interests share of assets and liabilities	(9,099)	(8,935)	(6,235)
Add ExxonMobil share of debt-financed equity company net assets		4,766	6,109	5,775
	Total capital employed	205,852	200,368	182,781
Total corporate sources: debt and equity perspective
Notes and loans payable		17,468	15,808	3,653
Long-term debt		11,653	6,891	7,928
ExxonMobil share of equity		174,399	174,003	165,863
Less noncontrolling interests share of total debt		(2,434)	(2,443)	(438)
Add ExxonMobil share of equity company debt		4,766	6,109	5,775
	Total capital employed	205,852	200,368	182,781

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				2014	2013	2012
				(millions of dollars)
Net income attributable to ExxonMobil				32,520	32,580	44,880
Financing costs (after tax)
	Gross third-party debt			(140)	(163)	(401)
	ExxonMobil share of equity companies			(256)	(239)	(257)
	All other financing costs – net			(68)	83	100
		Total financing costs		(464)	(319)	(558)
			Earnings excluding financing costs	32,984	32,899	45,438
Average capital employed				203,110	191,575	179,094
Return on average capital employed – corporate total				16.2%	17.2%	25.4%

38

QUARTERLY INFORMATION

		2014					2013
		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)
	and natural gas liquids,	2,148	2,048	2,065	2,182	2,111	2,193	2,182	2,199	2,235	2,202
	synthetic oil and bitumen
Refinery throughput		4,509	4,454	4,591	4,349	4,476	4,576	4,466	4,847	4,452	4,585
Petroleum product sales		5,817	5,841	5,999	5,845	5,875	5,755	5,765	6,031	5,994	5,887
Natural gas production		(millions of cubic feet daily)
	available for sale	12,016	10,750	10,595	11,234	11,145	13,213	11,354	10,914	11,887	11,836
		(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)		4,151	3,840	3,831	4,054	3,969	4,395	4,074	4,018	4,216	4,175
		(thousands of metric tons)
Chemical prime product sales		6,128	6,139	6,249	5,719	24,235	5,910	5,831	6,245	6,077	24,063
Summarized financial data
Sales and other operating		(millions of dollars)
	revenue (2)(3)	101,312	105,719	103,206	83,868	394,105	103,378	103,050	108,390	106,018	420,836
Gross profit (4)		29,166	28,746	28,825	23,240	109,977	30,083	28,689	30,300	29,901	118,973
Net income attributable to
	ExxonMobil	9,100	8,780	8,070	6,570	32,520	9,500	6,860	7,870	8,350	32,580
Per share data		(dollars per share)
Earnings per common share (5)		2.10	2.05	1.89	1.56	7.60	2.12	1.55	1.79	1.91	7.37
Earnings per common share
	– assuming dilution (5)	2.10	2.05	1.89	1.56	7.60	2.12	1.55	1.79	1.91	7.37
Dividends per common share		0.63	0.69	0.69	0.69	2.70	0.57	0.63	0.63	0.63	2.46
Common stock prices
	High	101.22	104.61	104.76	97.20	104.76	91.93	93.50	95.49	101.74	101.74
	Low	89.25	96.24	93.62	86.19	86.19	86.59	85.02	85.61	84.79	84.79

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

(2)   Amounts in first three quarters of 2014 have been reclassified.

(3)   Includes amounts for sales-based taxes.

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

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

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common 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 433,941 registered shareholders of ExxonMobil common stock at December 31, 2014. At January 31, 2015, the registered shareholders of ExxonMobil common stock numbered 432,983.

On January 28, 2015, the Corporation declared a $0.69 dividend per common share, payable March 10, 2015.

39

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

FUNCTIONAL EARNINGS			2014	2013	2012
			(millions of dollars, except per share amounts)
Earnings (U.S. GAAP)
Upstream
	United States		5,197	4,191	3,925
	Non-U.S.		22,351	22,650	25,970
Downstream
	United States		1,618	2,199	3,575
	Non-U.S.		1,427	1,250	9,615
Chemical
	United States		2,804	2,755	2,220
	Non-U.S.		1,511	1,073	1,678
Corporate and financing			(2,388)	(1,538)	(2,103)
		Net income attributable to ExxonMobil (U.S. GAAP)	32,520	32,580	44,880
Earnings per common share			7.60	7.37	9.70
Earnings per common share – assuming dilution			7.60	7.37	9.70

References in this discussion to total corporate earnings mean net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income 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.

40

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

FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, 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; the outcome of commercial negotiations; 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. 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.

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 2 billion more than in 2010. 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 35 percent from 2010 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 40 percent from 2010 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 85 percent by 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. Natural gas demand is likely to grow most significantly and become the leading source of generated electricity by 2040, reflecting the efficiency of gas-fired power plants. Today, coal has the largest fuel share in the power sector, but its share is likely to decline significantly by 2040 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by hydropower and wind, are also expected to grow significantly over the period.

41

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

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability and ease of transportation, distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is expected to grow to approximately 115 million barrels of oil‑equivalent per day, an increase of almost 30 percent from 2010. 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 is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise about 65 percent from 2010 to 2040, with about half 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. About two-thirds of the growth in natural gas supplies is expected to be from unconventional sources, which will account for close to 35 percent of global gas supplies by 2040. The worldwide liquefied natural gas (LNG) market is expected to more than triple by 2040, stimulated by growing natural gas demand.

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 less than 20 percent. Nuclear power is projected to grow significantly, as many nations 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 close to 450 percent from 2010 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 total oil and gas energy needs worldwide over the period 2014‑2040 will be about $28 trillion (measured in 2013 dollars) or more than $1 trillion per year on average.

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

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

42

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

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’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the next few years. However, actual volumes will vary from year to year due to the timing of individual project start-ups and other capital activities, 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 other factors described in Item 1A. Risk Factors. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.

The markets for crude oil and natural gas have a history of significant price volatility. After some years of relatively stable prices, the end of 2014 saw crude prices drop to levels not seen since 2009. 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. 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 continue to be successful in a variety of market conditions. This is the outcome of disciplined investment, cost management, and asset enhancement programs.

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. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition 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 products and services to customers.

ExxonMobil has an ownership interest in 30 refineries, located in 17 countries, with distillation capacity of 5.2 million barrels per day and lubricant basestock manufacturing capacity of 131 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 remains challenging. Demand weakness and overcapacity in the refining sector will continue to increase competitive pressure. In the near term, we see variability in refining margins, with some regions seeing weaker margins as new capacity additions outpace global demand. In North America, lower raw material and energy cost driven by increasing crude oil and natural gas production has strengthened refining margins over the past few years.  

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, in the near term, new capacity additions outpace the growth in global demand. Additionally, 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 refining business. ExxonMobil’s integration across the value chain, from refining to marketing, enhances overall value in both fuels and lubricants businesses.

In the retail fuels marketing business, competition has caused inflation-adjusted margins to decline. In 2014, ExxonMobil expanded its branded retail site network in the U.S. 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 distributor model. ExxonMobil is increasing investment in its fuels brands and developing multiple programs that will enhance the value of its consumer retail offer. 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 where competition is increasing.   

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient

43

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

projects. These investments capitalize on the Corporation’s world‑class scale and integration, demonstrated efficiency, advanced technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging growth opportunities around the globe. In 2014, the company commissioned the clean fuels project at the joint Saudi Aramco and ExxonMobil SAMREF Refinery in Yanbu, Saudi Arabia, to produce low sulfur gasoline and ultra‑low sulfur diesel. Construction started on a new delayed coker unit at the refinery in Antwerp, Belgium, to upgrade low-value bunker fuel into high‑value diesel products. The company also completed an expansion of lube basestock capacity at the refinery in Singapore, and neared completion on a lube basestock expansion in Baytown, Texas. A finished lubricant plant expansion in Tianjin, China, was completed and additional lubricant plant expansions in China, Singapore, Finland, and the U.S. are underway to support demand growth for finished lubricants and greases in key markets.

Chemical

Worldwide petrochemical demand continued to improve in 2014, 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 savings. Specialty product margins declined reflecting significant 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 2014, ExxonMobil began construction of 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 meet rapidly growing demand for premium polymers. Construction of new halobutyl rubber and hydrocarbon resin units also started in Singapore to further extend our specialty product capacity in Asia. At the joint venture facility in Al-Jubail, Saudi Arabia, construction continued on the specialty elastomers project that is expected to start-up in 2015.

REVIEW OF 2014 AND 2013 RESULTS
	2014	2013	2012
	(millions of dollars)
Earnings (U.S. GAAP)
Net income attributable to ExxonMobil (U.S. GAAP)	32,520	32,580	44,880

Upstream
			2014	2013	2012
			(millions of dollars)
Upstream
	United States		5,197	4,191	3,925
	Non-U.S.		22,351	22,650	25,970
		Total	27,548	26,841	29,895

2014

Upstream earnings were $27,548 million, up $707 million from 2013. Lower prices decreased earnings by $2.0 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 4.0 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.

2013

Upstream earnings were $26,841 million, down $3,054 million from 2012. Higher gas realizations, partially offset by lower liquids realizations, increased earnings by $390 million. Production volume and mix effects decreased earnings by $910 million. All other items, including lower net gains from asset sales, mainly in Angola, and higher expenses, reduced earnings by $2.5 billion. On an oil‑equivalent basis, production was down 1.5 percent compared to 2012. Excluding the impacts of entitlement

44

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

volumes, OPEC quota effects and divestments, production was essentially flat. Liquids production of 2.2 million barrels per day increased 17,000 barrels per day compared with 2012. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was up 1.6 percent, as project ramp‑up and lower downtime were partially offset by field decline.  Natural gas production of 11.8 billion cubic feet per day decreased 486 million cubic feet per day from 2012. Excluding the impacts of entitlement volumes and divestments, natural gas production was down 1.5 percent, as field decline was partially offset by higher demand, lower downtime, and project ramp‑up. Earnings from U.S. Upstream operations for 2013 were $4,191 million, up $266 million from 2012. Earnings outside the U.S. were $22,650 million, down $3,320 million from the prior year.

Upstream Additional Information
		2014	2013
		(thousands of barrels daily)
Volumes Reconciliation (Oil-equivalent production)(1)
Prior year		4,175	4,239
	Entitlements - Net Interest	(4)	(38)
	Entitlements - Price / Spend / Other	(43)	(9)
	Quotas	-	3
	Divestments	(31)	(26)
	United Arab Emirates Onshore Concession Expiry	(135)	-
	Growth / Other	7	6
Current Year		3,969	4,175
(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.

45

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

Downstream
			2014	2013	2012
			(millions of dollars)
Downstream
	United States		1,618	2,199	3,575
	Non-U.S.		1,427	1,250	9,615
		Total	3,045	3,449	13,190

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.

2013

Downstream earnings of $3,449 million decreased $9,741 million from 2012 driven by the absence of the $5.3 billion gain associated with the Japan restructuring. Lower margins, mainly refining, decreased earnings by $2.9 billion. Volume and mix effects decreased earnings by $310 million. All other items, including higher operating expenses, unfavorable foreign exchange impacts, and lower divestments, decreased earnings by $1.2 billion. Petroleum product sales of 5.9 million barrels per day decreased 287,000 barrels per day from 2012. U.S. Downstream earnings were $2,199 million, down $1,376 million from 2012. Non-U.S. Downstream earnings were $1,250 million, a decrease of $8,365 million from the prior year.

46

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

Chemical
			2014	2013	2012
			(millions of dollars)
Chemical
	United States		2,804	2,755	2,220
	Non-U.S.		1,511	1,073	1,678
		Total	4,315	3,828	3,898

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 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.

2013

Chemical earnings of $3,828 million were $70 million lower than 2012. The absence of the gain associated with the Japan restructuring decreased earnings by $630 million. Higher margins increased earnings by $480 million, while volume and mix effects increased earnings by $80 million. Prime product sales of 24.1 million metric tons were down 94,000 tons from 2012. U.S. Chemical earnings were $2,755 million, up $535 million from 2012. Non‑U.S. Chemical earnings were $1,073 million, $605 million lower than the prior year.

Corporate and Financing
	2014	2013	2012
	(millions of dollars)
Corporate and financing	(2,388)	(1,538)	(2,103)

2014

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

2013

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

47

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

LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
		2014	2013	2012
		(millions of dollars)
Net cash provided by/(used in)
	Operating activities	45,116	44,914	56,170
	Investing activities	(26,975)	(34,201)	(25,601)
	Financing activities	(17,888)	(15,476)	(33,868)
Effect of exchange rate changes		(281)	(175)	217
Increase/(decrease) in cash and cash equivalents		(28)	(4,938)	(3,082)
		(December 31)
Cash and cash equivalents		4,616	4,644	9,582
Cash and cash equivalents - restricted		42	269	341
Total cash and cash equivalents		4,658	4,913	9,923

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.

Total cash and cash equivalents were $4.9 billion at the end of 2013, $5.0 billion lower than the prior year. The major sources of funds in 2013 were net income including noncontrolling interests of $33.4 billion, the adjustment for the noncash provision of $17.2 billion for depreciation and depletion, and a net debt increase of $11.6 billion. The major uses of funds included spending for additions to property, plant and equipment of $33.7 billion, the purchase of ExxonMobil stock of $16.0 billion, dividends to shareholders of $10.9 billion and a change in working capital, excluding cash and debt, of $4.7 billion. Included in total cash and cash equivalents at year-end 2013 was $0.3 billion 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, 2014, the Corporation had unused committed short-term lines of credit of $6.3 billion and unused committed long-term lines of credit of $0.5 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. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, the impact of fiscal and commercial terms, crude oil and natural gas prices, weather events, and regulatory changes. 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.

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2014 were $38.5 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an average investment profile of about $34 billionper year for the next few years. Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of

48

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

development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of cash flows from operating activities.

Cash Flow from Operating Activities

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.

2013

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

Cash Flow from Investing Activities

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.

2013

Cash used in investment activities netted to $34.2 billion in 2013, $8.6 billion higher than 2012. Spending for property, plant and equipment of $33.7 billion decreased $0.6 billion from 2012. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $2.7 billion compared to $7.7 billion in 2012. Additional investments and advances were $3.8 billion higher in 2013.

Cash Flow from Financing Activities

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. Purchases may be increased, decreased or discontinued at any time without prior notice.

49

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

2013

Cash used in financing activities was $15.5 billion in 2013, $18.4 billion lower than 2012. Dividend payments on common shares increased to $2.46 per share from $2.18 per share and totaled $10.9 billion, a pay-out of 33 percent of net income. Total debt increased $11.1 billion to $22.7 billion at year‑end.

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

During 2013, Exxon Mobil Corporation purchased 177 million shares of its common stock for the treasury at a gross cost of $16.0 billion. 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 3.7 percent from 4,502 million to 4,335 million at the end of 2013. 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, 2014. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

		Payments Due by Period
		Note			2020
		Reference		2016-	and
Commitments		Number	2015	2019	Beyond	Total
		(millions of dollars)
Long-term debt  (1)		14	-	6,755	4,898	11,653
	– Due in one year  (2)	6	770	-	-	770
Asset retirement obligations  (3)		9	1,055	2,763	9,606	13,424
Pension and other postretirement obligations  (4)		17	1,524	4,346	20,664	26,534
Operating leases  (5)		11	2,034	2,883	1,296	6,213
Unconditional purchase obligations  (6)		16	150	608	337	1,095
Take-or-pay obligations  (7)			2,973	10,671	14,065	27,709
Firm capital commitments  (8)			16,065	7,893	1,643	25,601

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 $9.0 billion as of December 31, 2014, 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 $375 million.

(2)   The amount due in one year is included in notes and loans payable of $17,468 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 2015 and estimated benefit payments for unfunded plans in all years.

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

(6)   Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable 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 $1,095 million mainly pertain to pipeline throughput agreements and include $433 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 $27,709 million mainly pertain to pipeline, manufacturing supply and terminal agreements.

(8)   Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $25.6 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $13.9 billion was associated with projects in Africa, Canada, Australia, United Arab Emirates, Malaysia and Kazakhstan. 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, 2014, 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, 2014, the Corporation’s unused short-term committed lines of credit totaled approximately $6.3 billion (Note 6) and unused long-term committed lines of credit totaled approximately $0.5 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.

	2014	2013	2012
Fixed-charge coverage ratio (times)	46.9	55.7	62.4
Debt to capital (percent)	13.9	11.2	6.3
Net debt to capital (percent)	11.9	9.1	1.2

Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive 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.

52

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

CAPITAL AND EXPLORATION EXPENDITURES
		2014				2013
		U.S.	Non-U.S.		Total	U.S.	Non-U.S.		Total
		(millions of dollars)
Upstream (1)		9,401		23,326	32,727	9,145		29,086	38,231
Downstream		1,310		1,724	3,034	951		1,462	2,413
Chemical		1,690		1,051	2,741	963		869	1,832
Other		35		-	35	13		-	13
	Total	12,436		26,101	38,537	11,072		31,417	42,489
(1) Exploration expenses included.

Capital and exploration expenditures in 2014 were $38.5 billion, down 9 percent from 2013 due primarily to the absence of the $3.1 billion Celtic Exploration Ltd. acquisition in 2013. The Corporation anticipates an average investment profile of about $34 billion per year for the next few years. Actual spending could vary depending on the progress of individual projects and property acquisitions.

Upstream spending of $32.7 billion in 2014 was down 14 percent from 2013, reflecting the absence of $4.2 billion of property acquisition costs in 2013. Investments in 2014 included projects in the U.S. Gulf of Mexico, U.S. onshore drilling, exploration in Russia 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 65 percent of total proved reserves at year-end 2014, and has been over 60 percent for the last ten years, indicating that proved reserves are consistently moved from undeveloped to developed status.

Capital investments in the Downstream totaled $3.0 billion in 2014, an increase of $0.6 billion from 2013, mainly reflecting higher spending on crude oil transportation infrastructure. The Chemical capital expenditures of $2.7 billion increased $0.9 billion from 2013 with higher investments in the U.S.

TAXES
		2014	2013	2012
		(millions of dollars)
Income taxes		18,015	24,263	31,045
	Effective income tax rate	41%	48%	44%
Sales-based taxes		29,342	30,589	32,409
All other taxes and duties		35,515	36,396	38,857
	Total	82,872	91,248	102,311

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.

2013

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

53

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

ENVIRONMENTAL MATTERS

Environmental Expenditures
		2014	2013
		(millions of dollars)
Capital expenditures		2,666	2,474
Other expenditures		3,522	3,538
	Total	6,188	6,012

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and 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 2014 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $6.2 billion. The total cost for such activities is expected to remain in this range in 2015 and 2016 (with capital expenditures approximately 40 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 2014 for environmental liabilities were $780 million ($321 million in 2013) and the balance sheet reflects accumulated liabilities of $1,066 million as of December 31, 2014, and $773 million as of December 31, 2013.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

Worldwide Average Realizations(1)	2014	2013	2012
Crude oil and NGL ($/barrel)	87.42	97.48	100.29
Natural gas ($/kcf)	4.68	4.60	3.90
(1)  Consolidated subsidiaries.

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price 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 $350 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 $175 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 political events, OPEC actions 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 future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.

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. Increased demand for certain services and materials has resulted in higher operating and capital costs in recent years. 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.

55

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, 2017. ExxonMobil is evaluating 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 are more likely to be recovered than not.

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and 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 65 percent of total proved reserves at year-end 2014 (including both consolidated and equity company reserves), and has been over 60 percent for the last ten years, indicating that proved reserves are consistently moved from undeveloped to developed status.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the 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.

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

The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-

56

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

adjusted amount of these reserves may be included in the impairment 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.

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.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Potential trigger events for impairment evaluation include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and current period operating losses combined with a history and forecast of operating or cash flow losses.

In general, the Corporation does not view temporarily low prices or margins as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas 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.

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

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.

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

57

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

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.

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. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

For funded plans, including 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 2014 was 7.25 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 7 percent and 10 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 $170 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

58

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

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.

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.

59

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, 2014.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014, 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)

60

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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, 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 25, 2015

61

CONSOLIDATED STATEMENT OF INCOME

			Note
			Reference
			Number	2014	2013	2012
				(millions of dollars)
Revenues and other income
	Sales and other operating revenue (1)			394,105	420,836	451,509
	Income from equity affiliates		7	13,323	13,927	15,010
	Other income			4,511	3,492	14,162
		Total revenues and other income		411,939	438,255	480,681
Costs and other deductions
	Crude oil and product purchases			225,972	244,156	263,535
	Production and manufacturing expenses			40,859	40,525	38,521
	Selling, general and administrative expenses			12,598	12,877	13,877
	Depreciation and depletion			17,297	17,182	15,888
	Exploration expenses, including dry holes			1,669	1,976	1,840
	Interest expense			286	9	327
	Sales-based taxes (1)		19	29,342	30,589	32,409
	Other taxes and duties		19	32,286	33,230	35,558
		Total costs and other deductions		360,309	380,544	401,955
Income before income taxes				51,630	57,711	78,726
	Income taxes		19	18,015	24,263	31,045
Net income including noncontrolling interests				33,615	33,448	47,681
	Net income attributable to noncontrolling interests			1,095	868	2,801
Net income attributable to ExxonMobil				32,520	32,580	44,880
Earnings per common share (dollars)			12	7.60	7.37	9.70
Earnings per common share - assuming dilution (dollars)			12	7.60	7.37	9.70

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

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

62

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

			2014	2013	2012
			(millions of dollars)
Net income including noncontrolling interests			33,615	33,448	47,681
Other comprehensive income (net of income taxes)
	Foreign exchange translation adjustment		(5,847)	(3,620)	920
	Adjustment for foreign exchange translation (gain)/loss
		included in net income	152	(23)	(4,352)
	Postretirement benefits reserves adjustment (excluding amortization)		(4,262)	3,174	(3,574)
	Amortization and settlement of postretirement benefits reserves
		adjustment included in net periodic benefit costs	1,111	1,820	2,395
	Unrealized change in fair value of stock investments		(63)	-	-
	Realized (gain)/loss from stock investments included in net income		3	-	-
		Total other comprehensive income	(8,906)	1,351	(4,611)
Comprehensive income including noncontrolling interests			24,709	34,799	43,070
	Comprehensive income attributable to noncontrolling interests		421	760	1,251
Comprehensive income attributable to ExxonMobil			24,288	34,039	41,819

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

63

CONSOLIDATED BALANCE SHEET

				Note
				Reference	Dec. 31	Dec. 31
				Number	2014	2013
					(millions of dollars)
Assets
	Current assets
		Cash and cash equivalents			4,616	4,644
		Cash and cash equivalents - restricted			42	269
		Notes and accounts receivable, less estimated doubtful amounts		6	28,009	33,152
		Inventories
			Crude oil, products and merchandise	3	12,384	12,117
			Materials and supplies		4,294	4,018
		Other current assets			3,565	5,108
			Total current assets		52,910	59,308
	Investments, advances and long-term receivables			8	35,239	36,328
	Property, plant and equipment, at cost, less accumulated depreciation
		and depletion		9	252,668	243,650
	Other assets, including intangibles, net				8,676	7,522
			Total assets		349,493	346,808
Liabilities
	Current liabilities
		Notes and loans payable		6	17,468	15,808
		Accounts payable and accrued liabilities		6	42,227	48,085
		Income taxes payable			4,938	7,831
			Total current liabilities		64,633	71,724
	Long-term debt			14	11,653	6,891
	Postretirement benefits reserves			17	25,802	20,646
	Deferred income tax liabilities			19	39,230	40,530
	Long-term obligations to equity companies				5,325	4,742
	Other long-term obligations				21,786	21,780
			Total liabilities		168,429	166,313
Commitments and contingencies				16
Equity
	Common stock without par value
		(9,000 million shares authorized, 8,019 million shares issued)			10,792	10,077
	Earnings reinvested				408,384	387,432
	Accumulated other comprehensive income				(18,957)	(10,725)
	Common stock held in treasury
		(3,818 million shares in 2014 and 3,684 million shares in 2013)			(225,820)	(212,781)
			ExxonMobil share of equity		174,399	174,003
	Noncontrolling interests				6,665	6,492
			Total equity		181,064	180,495
			Total liabilities and equity		349,493	346,808

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

64

CONSOLIDATED STATEMENT OF CASH FLOWS

					Note
					Reference
					Number	2014	2013	2012
						(millions of dollars)
Cash flows from operating activities
	Net income including noncontrolling interests					33,615	33,448	47,681
	Adjustments for noncash transactions
		Depreciation and depletion				17,297	17,182	15,888
		Deferred income tax charges/(credits)				1,540	754	3,142
		Postretirement benefits expense
			in excess of/(less than) net payments			524	2,291	(315)
		Other long-term obligation provisions
			in excess of/(less than) payments			1,404	(2,566)	1,643
	Dividends received greater than/(less than) equity in current
		earnings of equity companies				(358)	3	(1,157)
	Changes in operational working capital, excluding cash and debt
		Reduction/(increase)		- Notes and accounts receivable		3,118	(305)	(1,082)
				- Inventories		(1,343)	(1,812)	(1,873)
				- Other current assets		(68)	(105)	(42)
		Increase/(reduction)		- Accounts and other payables		(6,639)	(2,498)	3,624
	Net (gain) on asset sales				5	(3,151)	(1,828)	(13,018)
	All other items - net					(823)	350	1,679
		Net cash provided by operating activities				45,116	44,914	56,170
Cash flows from investing activities
	Additions to property, plant and equipment					(32,952)	(33,669)	(34,271)
	Proceeds associated with sales of subsidiaries, property, plant
		and equipment, and sales and returns of investments			5	4,035	2,707	7,655
	Decrease/(increase) in restricted cash and cash equivalents					227	72	63
	Additional investments and advances					(1,631)	(4,435)	(598)
	Collection of advances					3,346	1,124	1,550
		Net cash used in investing activities				(26,975)	(34,201)	(25,601)
Cash flows from financing activities
	Additions to long-term debt					5,731	345	995
	Reductions in long-term debt					(69)	(13)	(147)
	Additions to short-term debt					-	16	958
	Reductions in short-term debt					(745)	(756)	(4,488)
	Additions/(reductions) in debt with three months or less maturity					2,049	12,012	(226)
	Cash dividends to ExxonMobil shareholders					(11,568)	(10,875)	(10,092)
	Cash dividends to noncontrolling interests					(248)	(304)	(327)
	Changes in noncontrolling interests					-	(1)	204
	Tax benefits related to stock-based awards					115	48	130
	Common stock acquired					(13,183)	(15,998)	(21,068)
	Common stock sold					30	50	193
		Net cash used in financing activities				(17,888)	(15,476)	(33,868)
Effects of exchange rate changes on cash						(281)	(175)	217
Increase/(decrease) in cash and cash equivalents						(28)	(4,938)	(3,082)
Cash and cash equivalents at beginning of year						4,644	9,582	12,664
Cash and cash equivalents at end of year						4,616	4,644	9,582

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

65

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, 2011		9,512		330,939		(9,123)	(176,932)		154,396		6,348	160,744
	Amortization of stock-based awards	806		-		-	-		806		-	806
	Tax benefits related to stock-based awards	178		-		-	-		178		-	178
	Other	(843)		-		-	-		(843)		(1,441)	(2,284)
	Net income for the year	-		44,880		-	-		44,880		2,801	47,681
	Dividends - common shares	-		(10,092)		-	-		(10,092)		(327)	(10,419)
	Other comprehensive income	-		-		(3,061)	-		(3,061)		(1,550)	(4,611)
	Acquisitions, at cost	-		-		-	(21,068)		(21,068)		(34)	(21,102)
	Dispositions	-		-		-	667		667		-	667
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

			Held in
Common Stock Share Activity		Issued	Treasury	Outstanding
		(millions of shares)
Balance as of December 31, 2011		8,019	(3,285)		4,734
	Acquisitions	-	(244)		(244)
	Dispositions	-	12		12
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

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

66

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 2014 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

67

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.

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.

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

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

Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based 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. The valuation allowances are reviewed at least annually.

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.

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2014 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, 2017. ExxonMobil is evaluating the standard and its effect on the Corporation’s financial statements. 

3. Miscellaneous Financial Information

Research and development expenses totaled $971 million in 2014, $1,044 million in 2013 and $1,042 million in 2012.

Net income included before-tax aggregate foreign exchange transaction losses of $225 million, and gains of $155 million and $159 million in 2014, 2013 and 2012, respectively.

In 2014, 2013 and 2012, net income included gains of $187 million, $282 million and $328 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 $10.6 billion and $21.2 billion at December 31, 2014, and 2013, respectively.

Crude oil, products and merchandise as of year-end 2014 and 2013 consist of the following:

		2014	2013
		(billions of dollars)
Petroleum products		4.1	3.9
Crude oil		4.6	4.7
Chemical products		2.9	2.9
Gas/other		0.8	0.6
	Total	12.4	12.1

69

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, 2011		4,168	(13,291)	-	(9,123)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	842	(3,402)	-	(2,560)
Amounts reclassified from accumulated other
	comprehensive income	(2,600)	2,099	-	(501)
Total change in accumulated other comprehensive income		(1,758)	(1,303)	-	(3,061)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
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)

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2014	2013	2012
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	(152)	23	4,352
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(1,571)	(2,616)	(3,621)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(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		2014	2013	2012
		(millions of dollars)
Foreign exchange translation adjustment		292	218	(236)
Postretirement benefits reserves adjustment (excluding amortization)		2,009	(1,540)	1,619
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(460)	(796)	(1,226)
Unrealized change in fair value of stock investments		34	-	-
Realized change in fair value of stock investments included in net income		(2)	-	-
Total		1,873	(2,118)	157

70

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 2014, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows 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. For 2012, the amount includes before-tax gains related to the Japan restructuring, the sale of an Upstream property in Angola, exchanges of Upstream properties, the sale of U.S. service stations and the sale of Downstream affiliates in Malaysia and Switzerland. These gains are reported in “Other income” on the Consolidated Statement of Income.

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.

In 2012, the Corporation’s interest in a cost company was redeemed. As part of the redemption, a variable note due in 2035 issued by Mobil Services (Bahamas) Ltd. was assigned to a consolidated ExxonMobil affiliate. This note is no longer classified as third party long-term debt. This assignment did not result in a “Reduction in long-term debt” on the Statement of Cash Flows.

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

	2014	2013	2012
	(millions of dollars)
Cash payments for interest	380	426	555
Cash payments for income taxes	18,085	25,066	24,349

6. Additional Working Capital Information

			Dec. 31	Dec. 31
			2014	2013
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $113 million and $112 million		18,541	25,993
	Other, less reserves of $48 million and $28 million		9,468	7,159
		Total	28,009	33,152
Notes and loans payable
	Bank loans		473	723
	Commercial paper		16,225	14,051
	Long-term debt due within one year		770	1,034
		Total	17,468	15,808
Accounts payable and accrued liabilities
	Trade payables		25,286	30,920
	Payables to equity companies		6,589	6,587
	Accrued taxes other than income taxes		3,290	3,883
	Other		7,062	6,695
		Total	42,227	48,085

The Corporation has short-term committed lines of credit of $6.3 billion which were unused as of December 31, 2014. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was 0.3 percent and 0.4 percent at December 31, 2014, and 2013, respectively.

71

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, natural gas marketing, and refining operations 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 14 percent, 13 percent and 16 percent in the years 2014, 2013 and 2012, 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. In compliance with the sanctions and all general and specific licenses, prohibited activities involving offshore Russia in the Black Sea, Arctic regions, and onshore western Siberia have been wound down. The Corporation's maximum exposure to loss from these joint ventures as of December 31, 2014, is $1.0 billion.

		2014			2013			2012
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		183,708		55,855	236,161		68,084	224,953		67,572
Income before income taxes		65,549		19,014	69,454		19,999	69,411		20,882
Income taxes		20,520		5,684	21,618		6,069	20,703		5,868
	Income from equity affiliates	45,029		13,330	47,836		13,930	48,708		15,014
Current assets		49,905		16,802	62,398		19,545	59,612		18,483
Long-term assets		110,754		33,619	116,450		35,695	111,131		33,798
	Total assets	160,659		50,421	178,848		55,240	170,743		52,281
Current liabilities		37,333		11,472	54,550		15,243	49,698		14,265
Long-term liabilities		66,231		19,470	68,857		20,873	68,855		19,715
	Net assets	57,095		19,479	55,441		19,124	52,190		18,301

72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A list of significant equity companies as of December 31, 2014, 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
Chalmette Refining, LLC	50
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 USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

8. Investments, Advances and Long-Term Receivables

			Dec. 31,	Dec. 31,
			2014	2013
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,017	19,619
	Advances		9,818	10,476
		Total equity company investments and advances	29,835	30,095
Companies carried at cost or less and stock investments carried at fair value			526	115
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $2,662 million and $2,938 million		4,878	6,118
		Total	35,239	36,328

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Property, Plant and Equipment and Asset Retirement Obligations

		December 31, 2014		December 31, 2013
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,170	205,308	336,359	197,554
Downstream		53,327	22,639	54,456	23,219
Chemical		30,717	14,918	29,487	13,965
Other		15,575	9,803	14,215	8,912
	Total	446,789	252,668	434,517	243,650

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.

Accumulated depreciation and depletion totaled $194,121 million at the end of 2014 and $190,867 million at the end of 2013. Interest capitalized in 2014, 2013 and 2012 was $344 million, $309 million and $506 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:

		2014	2013
		(millions of dollars)
Beginning balance		12,988	11,973
	Accretion expense and other provisions	871	785
	Reduction due to property sales	(151)	(97)
	Payments made	(724)	(664)
	Liabilities incurred	122	603
	Foreign currency translation	(908)	(344)
	Revisions	1,226	732
Ending balance		13,424	12,988

74

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:

			2014	2013	2012
			(millions of dollars)
Balance beginning at January 1			2,707	2,679	2,881
	Additions pending the determination of proved reserves		1,095	293	868
	Charged to expense		(28)	(52)	(95)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(160)	(107)	(631)
	Divestments/Other		(27)	(106)	(344)
Ending balance at December 31			3,587	2,707	2,679
Ending balance attributed to equity companies included above			645	13	3

Period end capitalized suspended exploratory well costs:

			2014	2013	2012
			(millions of dollars)
Capitalized for a period of one year or less			1,095	293	866
	Capitalized for a period of between one and five years		1,659	1,705	1,176
	Capitalized for a period of between five and ten years		544	470	401
	Capitalized for a period of greater than ten years		289	239	236
Capitalized for a period greater than one year - subtotal			2,492	2,414	1,813
		Total	3,587	2,707	2,679

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical 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.

			2014	2013	2012
Number of projects with first capitalized well drilled in the preceding 12 months			8	8	10
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		53	50	45
		Total	61	58	55

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Of the 53 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2014, 15 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 38 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 38 projects, which total $1,035 million.

			Years
		Dec. 31,	Wells
Country/Project		2014	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		8	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		12	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		38	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		28	2008 - 2011	Development activity under way, while continuing commercial discussions with the
				government.
- Kedung Keris		11	2011	Evaluating development plan to tie into planned production facilities.
- Natuna		118	1981 - 1983	Development activity under way, while continuing discussions with the government
				on contract terms pursuant to executed Heads of Agreement.
Kazakhstan
- Kairan		53	2004 - 2007	Evaluating commercialization and field development alternatives, while continuing
				discussions with the government regarding the development plan.
Malaysia
- Besar		18	1992 - 2010	Gas field off the east coast of Malaysia; progressing development plan.
- Bindu		2	1995	Awaiting capacity in existing/planned infrastructure.
Nigeria
- Bolia		15	2002 - 2006	Evaluating development plan, while continuing discussions with the government
				regarding regional hub strategy.
- Bosi		79	2002 - 2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Bosi Central		16	2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Owowo		50	2009 - 2012	Continuing discussions with the government regarding contract terms.
- 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		15	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		18	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		29	2008 - 2013	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.
- P'nyang		58	2012	Evaluating development alternatives to tie into existing/planned infrastructure.
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 2014 (38 projects)		1,035

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11. Leased Facilities

At December 31, 2014, 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 $6,213 million as indicated in the table. Estimated related rental income from noncancelable subleases is $70 million.

		Related
	Lease Payments	Sublease
	Under Minimum	Rental
	Commitments	Income
	(millions of dollars)
2015	2,034	31
2016	1,379	7
2017	774	6
2018	418	3
2019	312	3
2020 and beyond	1,296	20
Total	6,213	70

Net rental cost under both cancelable and noncancelable operating leases incurred during 2014, 2013 and 2012 were as follows:

	2014	2013	2012
	(millions of dollars)
Rental cost	4,077	3,841	3,851
Less sublease rental income	52	44	44
Net rental cost	4,025	3,797	3,807

12. Earnings Per Share

	2014	2013	2012
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	32,520	32,580	44,880
Weighted average number of common shares outstanding(millions of shares)	4,282	4,419	4,628
Earnings per common share(dollars) (1)	7.60	7.37	9.70
Dividends paid per common share (dollars)	2.70	2.46	2.18

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

77

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 $11.7 billion and $6.8 billion at December 31, 2014, and 2013, respectively, as compared to recorded book values of $11.3 billion and $6.5 billion at December 31, 2014, and 2013, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $5,500 million of long-term debt in the first quarter of 2014.

The fair value of long-term debt by hierarchy level at December 31, 2014, is: Level 1 $11,036 million; Level 2 $561 million; and Level 3 $63 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 $75 million at year-end 2014 and a net asset of $1 million at year-end 2013. 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 $110 million, $(7) million and $(23) million during 2014, 2013 and 2012, 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.

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Long-Term Debt

At December 31, 2014, long-term debt consisted of $11,341 million due in U.S. dollars and $312 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 $770 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 $5,500 million of long-term debt in the first quarter of 2014. The amounts of long-term debt maturing in each of the four years after December 31, 2015, in millions of dollars, are: 2016 – $537; 2017 – $2,993; 2018 – $872; and 2019 – $2,353. At December 31, 2014, the Corporation’s unused long-term credit lines were $0.5 billion.

Summarized long-term debt at year-end 2014 and 2013 are shown in the table below:

			2014	2013
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	-
	Floating-rate notes due 2017 (1)		750	-
	1.819% notes due 2019		1,750	-
	Floating-rate notes due 2019 (2)		500	-
	3.176% notes due 2024		1,000	-
XTO Energy Inc. (3)
	5.000% senior notes due 2015		-	132
	5.300% senior notes due 2015		-	243
	5.650% senior notes due 2016		207	212
	6.250% senior notes due 2017		477	489
	5.500% senior notes due 2018		383	389
	6.500% senior notes due 2018		474	485
	6.100% senior notes due 2036		199	200
	6.750% senior notes due 2037		309	312
	6.375% senior notes due 2038		236	238
Mobil Producing Nigeria Unlimited (4)
	Variable notes due 2015-2019		399	742
Esso (Thailand) Public Company Ltd.(5)
	Variable notes due 2015-2019		121	177
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2015-2051 (6)			2,611	2,527
Other U.S. dollar obligations (7)			104	112
Other foreign currency obligations			9	9
Capitalized lease obligations(8)			375	375
		Total long-term debt	11,653	6,891

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

(2)   Average effective interest rate of 0.4% in 2014.

(3)   Includes premiums of $219 million in 2014 and $271 million in 2013.

(4)   Average effective interest rate of 4.5% in 2014 and 4.6% in 2013.

(5)   Average effective interest rate of 2.4% in 2014 and 3.3% in 2013.

(6)   Average effective interest rate of 0.03% in 2014 and 0.06% in 2013.

(7)   Average effective interest rate of 4.2% in 2014 and 4.4% in 2013.

(8)   Average imputed interest rate of 7.0% in 2014 and 7.8% in 2013.

79

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 2014, remaining shares available for award under the 2003 Incentive Program were 108million.  

Restricted Stock and Restricted Stock Units. Awards totaling 9,775 thousand, 9,729 thousand, and 10,017 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2014, 2013 and 2012, 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, 2014.

	2014
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	45,207		78.29
2013 award issued in 2014	9,705		94.47
Vested	(10,286)		79.89
Forfeited	(187)		78.89
Issued and outstanding at December 31	44,439		81.45

Value of restricted stock and units	2014	2013	2012
Grant price (dollars)	95.20	94.47	87.24
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	858	843	797
Units settled in cash	73	76	77
Total value	931	919	874

As of December 31, 2014, there was $2,339 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 $831 million, $854 million and $854 million for 2014, 2013 and 2012, respectively. The income tax benefit recognized in income related to this compensation expense was $76 million, $78 million and $79 million for the same periods, respectively. The fair value of shares and units vested in 2014, 2013 and 2012 was $946 million, $1,040 million and $926 million, respectively. Cash payments of $73 million, $67 million and $66 million for vested restricted stock units settled in cash were made in 2014, 2013 and 2012, respectively.

80

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, 2014, 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, 2014
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			3,506		41	3,547
	Other			2,920		3,982	6,902
		Total		6,426		4,023	10,449
(1) ExxonMobil share.

The debt-related guarantees shown above include a $3.4 billion completion guarantee provided to lenders in support of the project financing for the Papua New Guinea Liquefied Natural Gas project. On February 4, 2015, the obligations under this guarantee were terminated per the terms of the loan agreement.

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
		2016-	2020 and
	2015	2019	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	150	608		337	1,095

(1)   Undiscounted obligations of $1,095 million mainly pertain to pipeline throughput agreements and include $433 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $168 million, totaled $927 million.

81

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) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. 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 (ICC).Following the favorable ICSID decision in the fourth quarter of 2014, ExxonMobil recognized earnings of $269 million, net of the remaining asset value, for the proceeds received from the earlier ICC award.           

Judgment was entered on the ICSID award by the United States District Court for the Southern District of New York on October 10, 2014. A motion to vacate that judgment on procedural grounds was filed by the Republic of Venezuela on October 14, 2014, which was denied by the court. Thereafter, the Republic of Venezuela filed a motion 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.

On October 23, 2014, the Republic of Venezuela filed with ICSID an application to revise the ICSID award such that it requires repayment of the value of the ICC award to PdVSA at the same time as payment is made to the ExxonMobil affiliates for the ICSID award and that provision be made for interest on the amount to be repaid. Thereafter, pursuant to ICSID arbitration rules, the ICSID award was stayed pending further action of the Tribunal. On October 27, 2014, ExxonMobil filed a response with ICSID that contests the application for revision of that award on both factual and jurisdictional grounds. On February 2, 2015, the Republic of Venezuela filed an application to annul the ICSID award. The 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. Upon registration of the application with ICSID on February 9, 2015, a further stay of the ICSID award was entered.

The federal court in New York has stayed its judgment until such time as the stays of the ICSID award entered following the Government of Venezuela’s filing of its two applications have 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 have appealed that judgment. 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. 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.

82

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
		2014	2013	2014	2013	2014	2013
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.00	5.00	3.10	4.30	4.00	5.00
	Long-term rate of compensation increase	5.75	5.75	5.30	5.40	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	17,304	19,779	27,357	28,670	7,868	9,058
	Service cost	677	801	590	697	140	176
	Interest cost	807	749	1,138	1,076	383	352
	Actuarial loss/(gain)	3,192	(1,520)	4,929	(1,454)	1,522	(1,267)
	Benefits paid (1) (2)	(1,427)	(2,520)	(1,366)	(1,311)	(525)	(511)
	Foreign exchange rate changes	-	-	(2,540)	(284)	(48)	(43)
	Amendments, divestments and other	(24)	15	(61)	(37)	96	103
Benefit obligation at December 31		20,529	17,304	30,047	27,357	9,436	7,868
Accumulated benefit obligation at December 31		16,385	13,989	26,318	23,949	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2014 and 2013, other postretirement benefits paid are net of $21 million and $20 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 2016 and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $91 million and the postretirement benefit obligation by $1,070 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $69 million and the postretirement benefit obligation by $844 million.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Change in plan assets
	Fair value at January 1	11,190	12,632	19,283	18,090	620	581
	Actual return on plan assets	1,497	617	3,153	1,604	41	64
	Foreign exchange rate changes	-	-	(1,738)	(270)	-	-
	Company contribution	1,476	101	554	919	31	35
	Benefits paid(1)	(1,248)	(2,171)	(912)	(869)	(224)	(60)
	Other	-	11	(245)	(191)	-	-
Fair value at December 31		12,915	11,190	20,095	19,283	468	620

(1)   Benefit payments for funded plans.

83

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.
		2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(4,590)	(3,547)	(2,113)	(941)
	Unfunded plans	(3,024)	(2,567)	(7,839)	(7,133)
Total		(7,614)	(6,114)	(9,952)	(8,074)

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
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31  (1)	(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	1	302	201	-	-
	Current liabilities	(340)	(275)	(325)	(358)	(369)	(359)
	Postretirement benefits reserves	(7,274)	(5,840)	(9,929)	(7,917)	(8,599)	(6,889)
Total recorded		(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,589	4,780	9,642	7,943	2,997	1,603
	Prior service cost	27	60	429	665	51	65
Total recorded in accumulated other
	comprehensive income	6,616	4,840	10,071	8,608	3,048	1,668

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

84

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
				2014	2013	2012	2014	2013	2012	2014	2013	2012
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31		(percent)
	Discount rate			5.00	4.00	5.00	4.30	3.80	4.00	5.00	4.00	5.00
	Long-term rate of return on funded assets			7.25	7.25	7.25	6.30	6.40	6.60	7.25	7.25	7.25
	Long-term rate of compensation increase			5.75	5.75	5.75	5.40	5.50	5.40	5.75	5.75	5.75
Components of net periodic benefit cost				(millions of dollars)
	Service cost			677	801	665	590	697	648	140	176	134
	Interest cost			807	749	820	1,138	1,076	1,145	383	352	380
	Expected return on plan assets			(799)	(835)	(789)	(1,193)	(1,128)	(1,109)	(37)	(41)	(38)
	Amortization of actuarial loss/(gain)			409	646	576	628	852	844	116	228	170
	Amortization of prior service cost			8	7	7	120	117	117	14	21	34
	Net pension enhancement and
	curtailment/settlement cost(1)			276	723	333	-	22	1,540	-	-	-
Net periodic benefit cost				1,378	2,091	1,612	1,283	1,636	3,185	616	736	680
	(1)	Non-U.S. net pension enhancement and curtailment/settlement cost for 2012 includes $1,420 million (on a consolidated-company, before-tax basis) of accumulated other comprehensive income for the postretirement benefit reserves adjustment that was recycled into earnings and included in the Japan restructuring gain reported in “Other income”.
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)			2,494	(1,302)	1,885	2,969	(1,938)	1,906	1,518	(1,290)	1,008
	Amortization of actuarial (loss)/gain			(685)	(1,369)	(909)	(628)	(874)	(2,384)	(116)	(228)	(170)
	Prior service cost/(credit)			(25)	-	-	(70)	30	71	-	-	-
	Amortization of prior service (cost)/credit			(8)	(7)	(7)	(120)	(117)	(117)	(14)	(21)	(34)
	Foreign exchange rate changes			-	-	-	(688)	(155)	271	(8)	(10)	3
Total recorded in other comprehensive income				1,776	(2,678)	969	1,463	(3,054)	(253)	1,380	(1,549)	807
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax			3,154	(587)	2,581	2,746	(1,418)	2,932	1,996	(813)	1,487

Costs for defined contribution plans were $393 million, $392 million and $382 million in 2014, 2013 and 2012, respectively.

85

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
		2014	2013	2012
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	(1,776)	2,678	(969)
	Non-U.S. pension	(1,463)	3,054	253
	Other postretirement benefits	(1,380)	1,549	(807)
Total (charge)/credit to other comprehensive income, before tax		(4,619)	7,281	(1,523)
(Charge)/credit to income tax (see Note 4)		1,549	(2,336)	393
(Charge)/credit to investment in equity companies		(81)	49	(49)
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	(3,151)	4,994	(1,179)
Charge/(credit) to equity of noncontrolling interests		85	(279)	(124)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		(3,066)	4,715	(1,303)

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset 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 for the non-U.S. plans in aggregate 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.

86

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:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		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.

87

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Other Postretirement
				Fair Value Measurement
			at December 31, 2014, Using:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(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

88

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

			U.S. Pension									Non-U.S. Pension
			Fair Value Measurement									Fair Value Measurement
			at December 31, 2013, Using:									at December 31, 2013, Using:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-		2,514	(1)		-		2,514		-			3,046	(1)		-		3,046
		Non-U.S.		-		2,622	(1)		-		2,622		294	(2)		5,608	(1)		-		5,902
	Private equity			-		-			523	(3)	523		-			-			502	(3)	502
	Debt securities
		Corporate		-		3,430	(4)		-		3,430		-			2,125	(4)		-		2,125
		Government		-		2,056	(4)		-		2,056		272	(5)		7,100	(4)		-		7,372
		Asset-backed		-		6	(4)		-		6		-			103	(4)		-		103
	Real estate funds			-		-			-		-		-			-			136	(6)	136
	Cash			-		27	(7)		-		27		57			20	(8)		-		77
Total at fair value				-		10,655			523		11,178		623			18,002			638		19,263
	Insurance contracts
		at contract value									12										20
Total plan assets											11,190										19,283

(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.

89

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Other Postretirement
			Fair Value Measurement
			at December 31, 2013, Using:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(Level 1)	(Level 2)		(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	157	(1)	-		157
		Non-U.S.		-	149	(1)	-		149
	Private equity			-	-		9	(2)	9
	Debt securities
		Corporate		-	129	(3)	-		129
		Government		-	168	(3)	-		168
		Asset-backed		-	4	(3)	-		4
	Cash			-	4		-		4
Total at fair value				-	611		9		620

(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 2013 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2013
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	489	448	293	7
Net realized gains/(losses)	(1)	11	(13)	-
Net unrealized gains/(losses)	86	57	10	3
Net purchases/(sales)	(51)	(14)	(154)	(1)
Fair value at December 31	523	502	136	9

90

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.
			2014	2013		2014	2013
		(millions of dollars)
For funded  pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		17,505	14,737		5,031	891
	Accumulated benefit obligation		14,493	12,342		4,590	689
	Fair value of plan assets		12,915	11,189		3,890	611
For unfunded  pension plans:
	Projected benefit obligation		3,024	2,567		7,839	7,133
	Accumulated benefit obligation		1,892	1,647		6,573	6,070

					Other
		Pension Benefits			Postretirement
		U.S.		Non-U.S.	Benefits
		(millions of dollars)
Estimated 2015 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain)  (1)		1,001	753		211
	Prior service cost  (2)		6	105		14

(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 2015		-	560	-		-
Benefit payments expected in:
	2015	1,628	1,194	467		24
	2016	1,554	1,213	479		25
	2017	1,529	1,278	490		26
	2018	1,445	1,298	499		28
	2019	1,410	1,339	507		29
	2020 - 2024	6,714	6,988	2,613		172

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.

91

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 $129 million and $202 million in 2014 and 2012, 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, 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
As of December 31, 2012
Earnings after income tax		3,925		25,970		3,575		9,615		2,220		1,678		(2,103)		44,880
Earnings of equity companies included above		1,759		11,900		6		387		183		1,267		(492)		15,010
Sales and other operating revenue (1)		11,039		27,673		125,088		248,959		14,723		24,003		24		451,509
Intersegment revenue		8,764		47,507		20,963		62,130		12,409		9,750		258		-
Depreciation and depletion expense		5,104		7,340		594		1,280		376		508		686		15,888
Interest revenue		-		-		-		-		-		-		117		117
Interest expense		37		13		3		36		-		(1)		239		327
Income taxes		2,025		25,362		1,811		1,892		755		232		(1,032)		31,045
Additions to property, plant and equipment		9,697		21,769		480		1,153		338		659		1,083		35,179
Investments in equity companies		4,020		9,147		195		2,069		233		3,143		(277)		18,530
Total assets		86,146		140,848		18,451		40,956		7,238		18,886		21,270		333,795

(1)   Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and   $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

92

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Geographic
Sales and other operating revenue (1)		2014	2013	2012
		(millions of dollars)
United States		148,713	152,820	150,865
Non-U.S.		245,392	268,016	300,644
	Total	394,105	420,836	451,509
Significant non-U.S. revenue sources include:
	Canada	36,072	35,924	34,325
	United Kingdom	31,346	34,061	33,600
	Belgium	20,953	20,973	23,567
	Italy	18,880	19,273	18,228
	France	17,639	18,444	19,601
	Singapore	15,407	15,623	14,606
	Germany	14,816	15,701	15,871

 (1)  Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

Long-lived assets		2014	2013	2012
		(millions of dollars)
United States		104,000	98,271	94,336
Non-U.S.		148,668	145,379	132,613
	Total	252,668	243,650	226,949
Significant non-U.S. long-lived assets include:
	Canada	43,858	41,522	31,979
	Australia	15,328	14,258	13,415
	Nigeria	12,265	12,343	12,216
	Singapore	9,620	9,570	9,700
	Kazakhstan	9,138	8,530	7,785
	Angola	9,057	8,262	8,238
	Papua New Guinea	6,099	5,768	4,599
	Norway	5,139	6,542	7,040

93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19. Income, Sales-Based and Other Taxes

						2014				2013				2012
				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		1,456		14,755	16,211	1,073		22,115	23,188	1,791		25,650	27,441
		Deferred - net		900		1,398	2,298	(116)		757	641	1,097		1,816	2,913
	U.S. tax on non-U.S. operations			5		-	5	37		-	37	89		-	89
			Total federal and non-U.S.	2,361		16,153	18,514	994		22,872	23,866	2,977		27,466	30,443
	State (1)			(499)		-	(499)	397		-	397	602		-	602
			Total income tax expense	1,862		16,153	18,015	1,391		22,872	24,263	3,579		27,466	31,045
Sales-based taxes				6,310		23,032	29,342	5,992		24,597	30,589	5,785		26,624	32,409
All other taxes and duties
	Other taxes and duties			378		31,908	32,286	955		32,275	33,230	1,406		34,152	35,558
	Included in production and
		manufacturing expenses		1,454		1,179	2,633	1,318		1,182	2,500	1,242		1,308	2,550
	Included in SG&A expenses			155		441	596	150		516	666	154		595	749
		Total other taxes and duties		1,987		33,528	35,515	2,423		33,973	36,396	2,802		36,055	38,857
			Total	10,159		72,713	82,872	9,806		81,442	91,248	12,166		90,145	102,311

(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 net credits of $40 million in 2014 and $310 million in 2013 and a net charge of $244 million in 2012 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 2014, 2013 and 2012 is as follows:

			2014	2013	2012
			(millions of dollars)
Income before income taxes
	United States		9,080	9,746	11,222
	Non-U.S.		42,550	47,965	67,504
		Total	51,630	57,711	78,726
Theoretical tax			18,071	20,199	27,554
Effect of equity method of accounting			(4,663)	(4,874)	(5,254)
Non-U.S. taxes in excess of theoretical U.S. tax			5,442	10,528	8,434
U.S. tax on non-U.S. operations			5	37	89
State taxes, net of federal tax benefit			(324)	258	391
Other			(516)	(1,885)	(169)
		Total income tax expense	18,015	24,263	31,045
Effective tax rate calculation
Income taxes			18,015	24,263	31,045
ExxonMobil share of equity company income taxes			5,678	6,061	5,859
		Total income taxes	23,693	30,324	36,904
Net income including noncontrolling interests			33,615	33,448	47,681
		Total income before taxes	57,308	63,772	84,585
Effective income tax rate			41%	48%	44%

94

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:		2014	2013
		(millions of dollars)
Property, plant and equipment		51,643	50,884
Other liabilities		4,359	3,474
	Total deferred tax liabilities	56,002	54,358
Pension and other postretirement benefits		(8,140)	(6,573)
Asset retirement obligations		(6,162)	(6,083)
Tax loss carryforwards		(4,099)	(3,393)
Other assets		(6,446)	(6,246)
	Total deferred tax assets	(24,847)	(22,295)
Asset valuation allowances		2,570	2,491
	Net deferred tax liabilities	33,725	34,554

In 2014, asset valuation allowances of $2,570 million increased by $79 million and included additional net provisions of $340 million and effects of foreign currency translation of $(261) 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		2014	2013
		(millions of dollars)
Other current assets		(2,001)	(3,575)
Other assets, including intangibles, net		(3,955)	(2,822)
Accounts payable and accrued liabilities		451	421
Deferred income tax liabilities		39,230	40,530
	Net deferred tax liabilities	33,725	34,554

The Corporation had $51 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

95

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		2014	2013	2012
		(millions of dollars)
Balance at January 1		7,838	7,663	4,922
	Additions based on current year's tax positions	1,454	1,460	1,662
	Additions for prior years' tax positions	448	464	2,559
	Reductions for prior years' tax positions	(532)	(249)	(535)
	Reductions due to lapse of the statute of limitations	(117)	(588)	(79)
	Settlements with tax authorities	(43)	(849)	(855)
	Foreign exchange effects/other	(62)	(63)	(11)
Balance at December 31		8,986	7,838	7,663

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 2014, 2013 and 2012 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. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 30 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 - 2014
Angola	2009 - 2014
Australia:	2000 - 2003
	2005
	2008 - 2014
Canada	2007 - 2014
Equatorial Guinea	2007 - 2014
Malaysia	2008 - 2014
Nigeria	2004 - 2014
Norway	2005 - 2014
Qatar	2008 - 2014
Russia	2011 - 2014
United Kingdom	2010 - 2014
United States	2006 - 2014

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 $42 million in interest expense on income tax reserves in 2014. 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 Corporation incurred $46 million in interest expense in 2012. The related interest payable balances were $205 million and $156 million at December 31, 2014, and 2013, respectively.

96

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 $3,223 million in 2014, $886 million in 2013, and $2,832 million in 2012. 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
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

97

				Canada/
			United	South				Australia/
Results of Operations			States	America	Europe	Africa	Asia		Oceania	Total
			(millions of dollars)
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
Consolidated Subsidiaries
2012 - Revenue
		Sales to third parties	6,977	1,804	5,835	3,672	6,536		1,275	26,099
		Transfers	6,996	5,457	6,366	16,905	9,241		932	45,897
			13,973	7,261	12,201	20,577	15,777		2,207	71,996
	Production costs excluding taxes		4,044	3,079	2,443	2,395	1,606		488	14,055
	Exploration expenses		391	292	274	234	513		136	1,840
	Depreciation and depletion		4,862	848	1,559	2,879	1,785		264	12,197
	Taxes other than income		1,963	89	513	1,702	2,248		446	6,961
	Related income tax		1,561	720	5,413	8,091	6,616		281	22,682
	Results of producing activities for consolidated
		subsidiaries	1,152	2,233	1,999	5,276	3,009		592	14,261
Equity Companies
2012 - Revenue
		Sales to third parties	1,284	-	6,380	-	20,017		-	27,681
		Transfers	1,108	-	67	-	5,693		-	6,868
			2,392	-	6,447	-	25,710		-	34,549
	Production costs excluding taxes		467	-	369	-	484		-	1,320
	Exploration expenses		9	-	17	-	-		-	26
	Depreciation and depletion		176	-	152	-	676		-	1,004
	Taxes other than income		42	-	3,569	-	6,658		-	10,269
	Related income tax		-	-	894	-	8,234		-	9,128
	Results of producing activities for equity companies		1,698	-	1,446	-	9,658		-	12,802
Total results of operations			2,850	2,233	3,445	5,276	12,667		592	27,063

98

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $12,856 million less at year-end 2014 and $13,667 million less at year-end 2013 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, 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
Consolidated Subsidiaries
As of December 31, 2013
	Property (acreage) costs		- Proved	13,881	3,595	188	874	1,620		863	21,021
			- Unproved	23,945	5,390	61	583	701		146	30,826
		Total property costs		37,826	8,985	249	1,457	2,321		1,009	51,847
	Producing assets			74,743	34,487	44,161	40,424	30,082		7,973	231,870
	Incomplete construction			5,640	11,811	2,219	5,913	8,387		4,194	38,164
		Total capitalized costs		118,209	55,283	46,629	47,794	40,790		13,176	321,881
	Accumulated depreciation and depletion			39,505	16,827	35,108	24,570	17,455		4,529	137,994
	Net capitalized costs for consolidated subsidiaries			78,704	38,456	11,521	23,224	23,335		8,647	183,887
Equity Companies
As of December 31, 2013
	Property (acreage) costs		- Proved	77	-	5	-	-		-	82
			- Unproved	40	-	-	-	17		-	57
		Total property costs		117	-	5	-	17		-	139
	Producing assets			5,206	-	6,039	-	8,397		-	19,642
	Incomplete construction			416	-	201	-	1,452		-	2,069
		Total capitalized costs		5,739	-	6,245	-	9,866		-	21,850
	Accumulated depreciation and depletion			1,646	-	4,778	-	4,706		-	11,130
	Net capitalized costs for equity companies			4,093	-	1,467	-	5,160		-	10,720

99

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 2014 were $29,115 million, down $4,508 million from 2013, due primarily to lower property acquisition costs and development costs. In 2013 costs were $33,623 million, up $2,477 million from 2012, due primarily to higher property acquisition costs partially offset by lower exploration costs. Total equity company costs incurred in 2014 were $2,677 million, up $335 million from 2013, 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 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
During 2012
	Consolidated Subsidiaries
		Property acquisition costs	- Proved		192	2	95	-	43		-	332
			- Unproved		1,717	74	24	15	-		31	1,861
		Exploration costs			601	405	454	520	554		248	2,782
		Development costs			7,172	7,601	2,637	3,081	3,347		2,333	26,171
		Total costs incurred for consolidated subsidiaries			9,682	8,082	3,210	3,616	3,944		2,612	31,146
	Equity Companies
		Property acquisition costs	- Proved		-	-	-	-	-		-	-
			- Unproved		14	-	-	-	-		-	14
		Exploration costs			45	-	34	-	-		-	79
		Development costs			504	-	156	-	651		-	1,311
		Total costs incurred for equity companies			563	-	190	-	651		-	1,404

100

Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2012, 2013, and 2014.

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 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.

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 2014 that were associated with production sharing contract arrangements was 11 percent of liquids, 9 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 2013 year-end proved reserves and 2014 year-end proved reserves, primarily reflect the revisions, extensions and discoveries in Canada and the United States.

101

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, 2012		1,660	118	317	1,463	1,721	170	5,449		905	3,106		653	10,113
	Revisions	25	33	14	20	(10)	5	87		3	265		(29)	326
	Improved recovery	6	-	-	-	1	-	7		-	-		-	7
	Purchases	163	-	20	-	-	-	183		36	-		-	219
	Sales	(15)	(1)	(8)	(58)	-	-	(82)		(4)	-		-	(86)
	Extensions/discoveries	166	138	8	41	9	-	362		164	234		-	760
	Production	(100)	(18)	(62)	(173)	(117)	(12)	(482)		(73)	(45)		(25)	(625)
December 31, 2012		1,905	270	289	1,293	1,604	163	5,524		1,031	3,560		599	10,714
Proportional interest in proved
	reserves of equity companies
January 1, 2012		348	-	29	-	1,255	-	1,632		483	-		-	2,115
	Revisions	(2)	-	1	-	131	-	130		15	-		-	145
	Improved recovery	16	-	-	-	-	-	16		-	-		-	16
	Purchases	-	-	-	-	-	-	-		-	-		-	-
	Sales	-	-	-	-	-	-	-		-	-		-	-
	Extensions/discoveries	-	-	-	-	-	-	-		-	-		-	-
	Production	(22)	-	(2)	-	(126)	-	(150)		(24)	-		-	(174)
December 31, 2012		340	-	28	-	1,260	-	1,628		474	-		-	2,102
Total liquids proved reserves
	at December 31, 2012	2,245	270	317	1,293	2,864	163	7,152		1,505	3,560		599	12,816
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

(See footnote on next page)

102

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, 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

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 9 million barrels in 2012, 11 million barrels in 2013 and 8 million barrels in 2014, as well as proved developed reserves of 9 million barrels in 2012, 9 million barrels in 2013 and 5 million barrels in 2014, and in addition, proved undeveloped reserves of 2 million barrels in 2013 and 3 million in 2014, in which there is a 30.4 percent noncontrolling interest.

103

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, 2012
		Consolidated subsidiaries	1,489	124	268	1,004	1,080	116	4,081		543	599	5,223
		Equity companies	264	-	28	-	1,423	-	1,715		-	-	1,715
Proved undeveloped reserves, as of
	December 31, 2012
		Consolidated subsidiaries	921	163	77	497	682	134	2,474		3,017	-	5,491
		Equity companies	84	-	-	-	303	-	387		-	-	387
Total liquids proved reserves at
	December 31, 2012		2,758	287	373	1,501	3,488	250	8,657		3,560	599	12,816
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)	4,233	534	13,713

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 53 million barrels in 2012, 62 million barrels in 2013 and 46 million barrels in 2014, as well as proved developed reserves of 52 million barrels in 2012, 55 million barrels in 2013 and 36 million barrels in 2014, and in addition, proved undeveloped reserves of 1 million barrels in 2012, 7 million barrels in 2013 and 10 million barrels in 2014, in which there is a 30.4 percent noncontrolling interest.

(2)   Includes total proved reserves attributable to Imperial Oil Limited of 2,841 million barrels in 2012, 2,867 million barrels in 2013 and 3,274 million barrels in 2014, as well as proved developed reserves of 543 million barrels in 2012, 1,417 million barrels in 2013 and 1,635 million barrels in 2014, and in addition, proved undeveloped reserves of 2,298 million barrels in 2012, 1,450 million barrels in 2013 and 1,639 million barrels in 2014, in which there is a 30.4 percent noncontrolling interest.

(3)   Includes total proved reserves attributable to Imperial Oil Limited of 599 million barrels in 2012, 579 million barrels in 2013 and 534 million barrels in 2014, as well as proved developed reserves of 599 million barrels in 2012, 579 million barrels in 2013 and 534 million barrels in 2014, 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 2014 Form 10-K.

104

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, 2012		26,254	835	3,586	982	6,471	7,247	45,375		17,676
	Revisions	(2,888)	168	168	2	(106)	465	(2,191)		(39)
	Improved recovery	-	-	-	-	-	-	-		7
	Purchases	503	-	6	-	-	-	509		304
	Sales	(181)	(20)	(140)	(12)	-	-	(353)		(145)
	Extensions/discoveries	4,045	95	184	-	59	-	4,383		1,490
	Production	(1,518)	(153)	(555)	(43)	(579)	(144)	(2,992)		(1,124)
December 31, 2012		26,215	925	3,249	929	5,845	7,568	44,731		18,169
Proportional interest in proved reserves
	of equity companies
January 1, 2012		112	-	10,169	-	20,566	-	30,847		7,256
	Revisions	49	-	17	-	252	-	318		198
	Improved recovery	-	-	-	-	-	-	-		16
	Purchases	-	-	-	-	-	-	-		-
	Sales	-	-	-	-	-	-	-		-
	Extensions/discoveries	-	-	-	-	-	-	-		-
	Production	(6)	-	(651)	-	(1,148)	-	(1,805)		(475)
December 31, 2012		155	-	9,535	-	19,670	-	29,360		6,995
Total proved reserves at December 31, 2012		26,370	925	12,784	929	25,515	7,568	74,091		25,164
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

(See footnotes on next page)

105

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, 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

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 488 billion cubic feet in 2012, 678 billion cubic feet in 2013 and 627 billion cubic feet in 2014, as well as proved developed reserves of 374 billion cubic feet in 2012, 368 billion cubic feet in 2013 and 300 billion cubic feet in 2014, and in addition, proved undeveloped reserves of 114 billion cubic feet in 2012, 310 billion cubic feet in 2013 and 327 billion cubic feet in 2014, 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.

106

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, 2012
		Consolidated subsidiaries	14,471	670	2,526	814	5,150	1,012	24,643		9,330
		Equity companies	126	-	7,057	-	18,431	-	25,614		5,984
Proved undeveloped reserves, as of
	December 31, 2012
		Consolidated subsidiaries	11,744	255	723	115	695	6,556	20,088		8,839
		Equity companies	29	-	2,478	-	1,239	-	3,746		1,011
Total proved reserves at December 31, 2012			26,370	925	12,784	929	25,515	7,568	74,091		25,164
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

(See footnotes on previous page)

107

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, 2012
		Future cash inflows from sales of oil and gas	250,382		293,910	66,769	160,261	192,491	104,334	1,068,147
		Future production costs	109,325		101,299	17,277	33,398	42,816	26,132	330,247
		Future development costs	37,504		44,518	16,505	13,363	13,083	11,435	136,408
		Future income tax expenses	43,772		34,692	23,252	63,246	75,261	21,405	261,628
		Future net cash flows	59,781		113,401	9,735	50,254	61,331	45,362	339,864
		Effect of discounting net cash flows at 10%	36,578		82,629	2,097	18,091	35,310	27,610	202,315
		Discounted future net cash flows	23,203		30,772	7,638	32,163	26,021	17,752	137,549
Equity Companies
	As of December 31, 2012
		Future cash inflows from sales of oil and gas	36,043		-	93,563	-	348,026	-	477,632
		Future production costs	7,040		-	64,988	-	112,980	-	185,008
		Future development costs	3,708		-	2,569	-	10,780	-	17,057
		Future income tax expenses	-		-	9,937	-	78,539	-	88,476
		Future net cash flows	25,295		-	16,069	-	145,727	-	187,091
		Effect of discounting net cash flows at 10%	14,741		-	8,133	-	76,979	-	99,853
		Discounted future net cash flows	10,554		-	7,936	-	68,748	-	87,238
Total consolidated and equity interests in
	standardized measure of discounted
	future net cash flows		33,757		30,772	15,574	32,163	94,769	17,752	224,787

(1)   Includes discounted future net cash flows attributable to Imperial Oil Limited of $24,690 million in 2012, in which there is a 30.4 percent noncontrolling interest.

108

					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, 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
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

(1)   Includes discounted future net cash flows attributable to Imperial Oil Limited of $25,160 million in 2013 and $30,189 million in 2014, in which there is a 30.4 percent noncontrolling interest.

109

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

Consolidated and Equity Interests				2012
					Total
				Share of	Consolidated
			Consolidated	Equity Method	and Equity
			Subsidiaries	Investees	Interests
			(millions of dollars)
Discounted future net cash flows as of December 31, 2011			152,244	86,560	238,804
Value of reserves added during the year due to extensions, discoveries,
	improved recovery and net purchases less related costs		7,952	531	8,483
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	(51,752)	(23,022)	(74,774)
	Development costs incurred during the year		24,596	1,186	25,782
	Net change in prices, lifting and development costs		(31,382)	5,656	(25,726)
	Revisions of previous reserves estimates		3,876	7,018	10,894
	Accretion of discount		19,676	8,846	28,522
Net change in income taxes			12,339	463	12,802
		Total change in the standardized measure during the year	(14,695)	678	(14,017)
Discounted future net cash flows as of December 31, 2012			137,549	87,238	224,787

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

110

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

Consolidated and Equity Interests (continued)				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

111

OPERATING SUMMARY (unaudited)

			2014	2013	2012	2011	2010
Production of crude oil, natural gas liquids, bitumen and synthetic oil
	Net production		(thousands of barrels daily)
		United States	454	431	418	423	408
		Canada/South America	301	280	251	252	263
		Europe	184	190	207	270	335
		Africa	489	469	487	508	628
		Asia	624	784	772	808	730
		Australia/Oceania	59	48	50	51	58
	Worldwide		2,111	2,202	2,185	2,312	2,422
Natural gas production available for sale
	Net production		(millions of cubic feet daily)
		United States	3,404	3,545	3,822	3,917	2,596
		Canada/South America	310	354	362	412	569
		Europe	2,816	3,251	3,220	3,448	3,836
		Africa	4	6	17	7	14
		Asia	4,099	4,329	4,538	5,047	4,801
		Australia/Oceania	512	351	363	331	332
	Worldwide		11,145	11,836	12,322	13,162	12,148
			(thousands of oil-equivalent barrels daily)
Oil-equivalent production(1)			3,969	4,175	4,239	4,506	4,447
Refinery throughput			(thousands of barrels daily)
		United States	1,809	1,819	1,816	1,784	1,753
		Canada	394	426	435	430	444
		Europe	1,454	1,400	1,504	1,528	1,538
		Asia Pacific	628	779	998	1,180	1,249
		Other Non-U.S.	191	161	261	292	269
	Worldwide		4,476	4,585	5,014	5,214	5,253
Petroleum product sales (2)
		United States	2,655	2,609	2,569	2,530	2,511
		Canada	496	464	453	455	450
		Europe	1,555	1,497	1,571	1,596	1,611
		Asia Pacific and other Eastern Hemisphere	1,085	1,206	1,381	1,556	1,562
		Latin America	84	111	200	276	280
	Worldwide		5,875	5,887	6,174	6,413	6,414
		Gasoline, naphthas	2,452	2,418	2,489	2,541	2,611
		Heating oils, kerosene, diesel oils	1,912	1,838	1,947	2,019	1,951
		Aviation fuels	423	462	473	492	476
		Heavy fuels	390	431	515	588	603
		Specialty petroleum products	698	738	750	773	773
	Worldwide		5,875	5,887	6,174	6,413	6,414
Chemical prime product sales (3)			(thousands of metric tons)
		United States	9,528	9,679	9,381	9,250	9,815
		Non-U.S.	14,707	14,384	14,776	15,756	16,076
	Worldwide		24,235	24,063	24,157	25,006	25,891

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 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.

112

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 25, 2015

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Randall M. Ebner, Leonard M. Fox and Catherine C. Shae 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 25, 2015.

/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

113

/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/    WILLIAM W. GEORGE (William W. George)	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/    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)

114

INDEX TO EXHIBITS

Exhibit	Description
3(i)	Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
3(ii)	By-Laws, as revised to April 27, 2011 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K on April 29, 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.*
10(iii)(c.2)	ExxonMobil Supplemental Pension Plan.*
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.*
10(iii)(f.4)	Standing resolution for non-employee director cash fees dated October 26, 2011 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).*
10(iii)(g.3)	1984 Mobil Compensation Management Retention Plan (incorporated by reference to Exhibit 10(iii)(g.3) to the Registrant’s Annual Report on Form 10-K for 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.

115

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.

116

EX-10.(III) (A3)

 

EXHIBIT 10(iii)(a.3)

November 25, 2014

Exxon Mobil Corporation

ExtendedProvisions for Restricted Stock Unit Agreements - Settlement in Shares

1.Effective Date and Creditof Restricted Stock Units.  If Grantee accepts the award on or before March 6, 2015, this Agreement willbecome 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 awardpackage. Subject to the terms and conditions of thisAgreement, each restricted stock unit ("unit") will entitle Grantee to receive in settlement ofthe 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 Risk of Forfeiture.  During the applicable restricted periods specified insection 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 nulland void; and

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

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

a)with respect to 50% of the units, onNovember 25, 2019; and

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

(i)  November 25, 2024, 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 thedeath of Grantee.   

5.No Obligation to Credit Units .   The Corporation will have no obligation to credit any units andwill have no otherobligation toGrantee withrespect to the subject matter of this Agreementif Grantee failsto accept the award on or before March 6, 2015.In addition, whether or not Grantee has accepted the award, the Corporation will have no obligation tocredit any units and will have no otherobligation to Grantee with respect to the subject matter of this Agreement if, before the units arecredited:  

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; or

c)Grantee fails to provide the Corporation with cash for any required taxes due upon crediting the units, if Grantee is required to do so under section 7.

1

6.Forfeiture of Units After Crediting .  Until the applicable restricted period specified in section 4 has expired, the unitsunder restriction will be forfeited orsubject 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 forwhich the applicable restricted periods have not expiredwill be automatically forfeited as ofthe date of termination, except to the extent the administrative authority determines Grantee may retain units issued under this Agreement.  

Detrimentalactivity   

If Grantee isdetermined tohave 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 ofthe date of such determination.  

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 inpart as the administrative authority deems necessary in order to comply with applicable law.

7.Taxes.  Notwithstanding the restrictions on transfer that otherwise apply, the Corporation in its sole discretion may withhold units or shares, either at the time of issuance, at the time the applicable restricted periods expire, 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. If the Corporation does not withhold units or shares to satisfy required taxes, in the alternative the Corporation may require Grantee to deposit with the Corporation cash in an amount determined by the Corporation to be necessary to satisfy required taxes. Notwithstanding any other provision of this Agreement, the Corporation will be under no obligation to credit units or to deliver shares to Grantee in settlement of any units if Grantee fails timely to deposit such amount with the Corporation. The Corporation in its sole discretion may also withhold any required taxes from dividends paid on the units. 

8.Form of Units; NoShareholder Status.  The unitswill be represented by book-entry credits inrecords maintained by or on behalf of the Corporation.Units will beunfunded andunsecured promises by the Corporation to deliver shares in the future upon the terms andsubject to theconditions ofthis Agreement. Grantee will not be a shareholder of the Corporation with respect to unitsprior to the time shares are actually registered in Grantee's name in settlementof such units in accordance with section 9. 

9.Settlement of Units .  If and when the applicable restricted period expires with respect toany units, subject to section 7, the Corporation will issueshares, 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 accountof 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.Change in Capitalization .  If during the applicable restricted periods a stock split, stock dividend, or otherrelevant change in capitalization of the Corporation occurs,the administrative authority will make such adjustments in the number of units credited toGrantee, or inthe number and type of securities deliverable to Grantee in settlement ofsuch units and used in determining dividend equivalent amounts, as the administrative authority maydetermine to be appropriate. Any resulting new unitsor securities credited withrespect to previously credited units that are still restricted under this Agreement will be delivered to andheld by or on behalf of the Corporation and will be subject to the same  

2

provisions, restrictions, andrequirements as those previously credited units.   

11.Limitson the Corporation's Obligations.  Notwithstanding anything else contained in thisAgreement, under no circumstances will theCorporation be required to credit any units or issue or deliver anyshares insettlement of units if doing sowould violate any law or listing requirement that the administrative authority determines to be applicable, or if Grantee has failed to provide for required taxes pursuant to section 7.  

12.Receipt or Access to Program.  Grantee acknowledges receipt of or access tothe full text of theProgram.   

13.Dividend Equivalents.  The Corporation will pay to Grantee cash with respect to eachcredited unit corresponding in amount, currency, andtiming to cash dividends that would be payable with respect to a share ofcommon stock outstanding on each record date that occurs during the applicable restricted period. Alternatively, the administrative authority may determine to reinvestsuch dividend equivalents in additional units which will be heldsubject to all the terms and conditions otherwise applicable to units under this Agreement.   

14.Addresses for Communications.  To facilitate communications regarding this Agreement, Grantee agrees tonotify the Corporation promptly of changes incurrent mailing and email addresses. Communications to the Corporation inconnection 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.  

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 betweenand among the Corporation, selected subsidiaries and other affiliatesof 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 theworld. This data includes Grantee's name, age, dateof birth, contact information, work location, employment status, tax status, social security number, salary, nationality, job title, shareownership, 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 andwithout charge, view such data and require necessary corrections toit. Such datawill 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 contractor 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 beengranted.   

17.Governing Law and Consent to Jurisdiction .  This Agreement and the Program are governed by thelaws of the State of NewYork without regard to any conflict of law rules. Any dispute arising out ofor 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 suchcourt. Similarly, the Corporation accepts such venue and submits to such jurisdiction.  

18.Entire Agreement .  This Agreement constitutes the entire understanding between Grantee and theCorporation 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  25, 2014 (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.

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) (C1)

 

EXHIBIT 10(iii)(c.1)

EXXONMOBIL SUPPLEMENTAL SAVINGS PLAN

(including Key Employee Supplemental Savings Plan)

Effective January 1, 2015

1. Purpose 

The purpose of this Plan is to provide a payment of approximately equivalent value from the general assets of Exxon Mobil Corporation (“Corporation”) to a person participating in the ExxonMobil Savings Plan (“Savings Plan”) who, because of the application of United States Internal Revenue Code (“Code”) sections 415 and 401(a)(17) is precluded from receiving employer contributions to the person's Savings Plan account to which the person would otherwise be entitled.

2. Benefits 

2.1          Eligibility 

A person is eligible to receive benefits under this Plan only if the person satisfies any of the following requirements:

(A)          The person becomes a retiree pursuant to section 4.1(A) (relating to age, service and LTD-eligibility requirements) or section 4.1(D) (relating to retiree grow-ins in connection with certain divestments) of the ExxonMobil Common Provisions; or

(B)          The person becomes a qualified plans retiree within the meaning of the ExxonMobil Pension Plan.

2.2          Benefit Formula

(A)          In General

As to any specific Savings Plan participant the total amount of payment under this Plan is an amount that is in general determined by notionally crediting on a monthly basis the amount of employer contributions that cannot be made to the Savings Plan for that person as a result of application to that person of Code sections 415 and 401(a)(17); except that, for those persons who, as of December 31, 1993, are classified at level 36 and are age 50 and above, only notional employer contributions made after such date are taken into account. This amount is enhanced in each instance by 120 percent of the long-term Applicable Federal Rate, compounded monthly, as of the last month of each calendar quarter as published by the Internal Revenue Service, and is then reduced, but not below zero, by the amount, if any, of the actuarial lump-sum value of the amount payable to the participant under the ExxonMobil Key Employee Additional Payments Plan that is not applied as an offset against the participant's benefit under the ExxonMobil Additional Payments Plan or the ExxonMobil Supplemental Pension Plan. For this purpose, the actuarial lump-sum value shall be determined using the mortality and interest rate assumptions set out in the ExxonMobil Pension Accounts Instrument.

(B)          Notional Interest Rate for Key Employees after Termination or Retirement

As to a participant who, immediately prior to his or her termination or retirement, has a Classification Level of 36 or above (“Key Employee”), "120 percent of the long-term Applicable Federal Rate, compounded monthly, as of the last month of each calendar quarter as published by the Internal Revenue Service" in paragraph (A) above shall be replaced with "Citibank Prime Lending Rate as of the last business day of each calendar quarter" for the period between date of termination or retirement and date of payment.

2.3          Calculation Methodology

The exact methodology used in determining such monthly credits and interest thereon will be established from time to time by the Plan Administrator. General guidelines to be followed are:

(A)          Required Participant Contributions

To the extent determined by those administering this Plan, a person is required to make regular employee contributions to the person's Savings Plan account up to the maximum permitted by the Code to receive credits under this Plan.

(B)          Discretionary Employee Contributions

Prior to July 1, 2002, a person may not enhance the amounts credited under this Plan by making discretionary employee contributions to the person's Savings Plan account.

1

3. Payment of Benefits

Payment of the benefit determined under article 2 above shall be made in a lump sum as soon as practicable following the latest of the following times:

(A)          the participant’s retirement from ExxonMobil;

(B)          In the case of a Key Employee, the six-month anniversary of the participant's termination of employment or retirement;

(C)          In the case of a participant whose Savings Plan account is transferred to a savings plan sponsored by Infineum USA Inc. or any of its affiliates ("Infineum"), the participant’s termination of employment from Infineum; or

(D)          In the case of a participant whose Savings Plan account is transferred to a savings plan sponsored by Tenneco, Inc. or any of its affiliates ("Tenneco"), the participant’s termination of employment from Tenneco.

4. Payment Upon Death

4.1          In General

If a person dies as an employee with eligibility for a pension death benefit under the ExxonMobil Pension Plan or as a retiree but before his benefit under this Plan is distributed to him, then such benefit shall be distributed as soon as practicable after death to the person’s beneficiary determined under section 4.2 below.

4.2          Designation of Beneficiaries

(A)          In General

A person entitled to receive a payment under this Plan may name one or more designated beneficiaries to receive such payment in the event of the person's death. Beneficiary designations shall be made in accordance with such procedures as the Plan Administrator may establish. Spousal consent to any designation is not required.

(B)          Default Beneficiaries

(1)           In General

If no specific designation is in effect, the deceased’s beneficiary is the person or persons in the first of the following classes of successive beneficiaries living at the time of death of the deceased:

(a)           spouse;

(b)           children who survive the participant or who die before the participant leaving children of their own who survive the participant;

(c)           parents;

(d)           brothers and sisters who survive the participant or who die before the participant leaving children of their own who survive the participant.

If there are no members of any class of such beneficiaries, payment is made to the deceased’s executors or administrators.

(2)           Allocation among Default Beneficiaries

If the same class of beneficiaries under paragraph (1) above contains two or more persons, they share equally, with further subdivision of such equal shares as next provided. In class (b), where a child dies before the participant leaving children who survive the participant, such child's share is subdivided equally among those children. In class (d), where a brother or sister dies before the participant leaving children who survive the participant, such brother or sister's share is subdivided equally among those children.

(3)           Definitions 

For purposes of this Section 4.2, "child" means a person's son or daughter by legitimate blood relationship or legal adoption; "parent" means a person's father or mother by legitimate blood relationship or legal adoption; "brother" or "sister" means another child of either or both of one's parents.

5. Miscellaneous 

5.1          Administration of Plan

The Plan Administrator shall be the Manager, Compensation, Benefit Plans and Policies, Human Resources Department, Exxon Mobil Corporation. The Plan Administrator shall have the right and authority to conclusively interpret this Plan for all purposes, including the determination of any person’s eligibility for benefits hereunder and the resolution of any and all appeals relating to claims by participants or beneficiaries, with any such interpretation being conclusive for all participants and beneficiaries.

2

5.2          Nature of Payments

Payments provided under this Plan are considered general obligations of the Corporation.

5.3          Assignment or Alienation

Except as provided in section 5.5 below, payments provided under this Plan may not be assigned or otherwise alienated or pledged.

5.4          Amendment or Termination

The Corporation reserves the right to amend or terminate this plan, in whole or in part, including the right at any time to reduce or eliminate any accrued benefits hereunder and to alter or amend the benefit formula set out herein.

5.5          Forfeiture of Benefits

No person shall be entitled to receive payments under this Plan and any payments received under this Plan shall be forfeited and returned if it is determined by the Corporation in its sole discretion, acting through its chief executive or such person or committee as the chief executive may designate, that a person otherwise entitled to a payment under this Plan or who has commenced receiving payments under this Plan:

(A)          engaged in gross misconduct harmful to the Corporation,

(B)          committed a criminal violation harmful to the Corporation,

(C)          had concealed actions described in paragraph (A) or (B) above which would have brought about termination from employment thereby making the person ineligible for benefits under this Plan,

(D)          separated from service prior to attaining age 65 without having received from the Corporation or its delegatee prior written approval for such termination, given in the sole discretion of the Corporation or its delegatee

and in the context of recognition that benefits under this Plan would not be forfeited upon such termination, or

(E)           had been terminated for cause.

3

EXXONMOBIL KEY EMPLOYEE SUPPLEMENTAL SAVINGS PLAN

K1. Purpose 

This Plan provides a payment from the general assets of Exxon Mobil Corporation (“Corporation”) to a person who, as of December 31, 1993,

(A)          was classified at level 36 or above,

(B)          was age 50 or above,

(C)          was a participant in the Thrift Plan of Exxon Corporation (“Thrift Plan”), and

(D)          had been precluded from receiving employer contributions to the person's account within the Thrift Plan to which the person would otherwise be entitled, because of the application of United States Internal Revenue Code (“Code”) sections 415 and 401(a)(17).

This plan expresses the Corporation's commitment to make such a payment at the time payment is made to the participant under the ExxonMobil Supplemental Savings Plan, and sets forth the method for doing so.

K2. Benefits 

K2.1       Benefit Formula

(A)          In General

As to a participant, the total amount of payment under this Plan shall be an amount that has been in general determined by notionally crediting on a monthly basis the amount of employer contributions that could not have been made to the Thrift Plan account of that person as a result of application to that person of Code sections 415 and 401(a)(17) from the date the person otherwise would have been an eligible participant in the Exxon Supplemental Thrift Plan until December 30, 1993. This amount shall be enhanced in each instance by 120 percent of the long-term Applicable Federal Rate, compounded monthly, as of the last month of each calendar quarter as published by the Internal Revenue Service. A participant in this Plan shall have a non-forfeitable right to this amount credited as of December 31, 1993 plus all enhancements.

(B)          Notional Interest Rate for Key Employees after Termination or Retirement

As to a participant who, immediately prior to his or her termination or retirement, has a Classification Level of 36 or above, "120 percent of the long-term Applicable Federal Rate, compounded monthly, as of the last month of each calendar quarter as published by the Internal Revenue Service" in paragraph (A) above shall be replaced with "Citibank Prime Lending Rate as of the last business day of each calendar quarter" for the period between date of termination or retirement and date of payment.

K2.2       Calculation Methodology

The exact methodology for such notional credits and interest thereon shall be determined by the Plan Administrator.

K3. Payment of Benefits

K3.1       Form of Payment

Payments under this Plan are made in the form of a lump sum single payment.

K3.2       Timing of Payment

Payment shall be made under this Plan at the same time as payment is made to the participant under the ExxonMobil Supplemental Savings Plan.

4

K4. Beneficiaries 

K4.1       Designation of Beneficiaries

A person entitled to receive a payment under this Plan may name one or more designees to receive such payment in the event of the person's death. Beneficiary designations shall be made in accordance with such procedures as the Plan Administrator may establish. Spousal consent to any designation is not required.

K4.2       Default Beneficiaries

(A)          In General

If no specific designation is in effect, the deceased’s beneficiary is the person or persons in the first of the following classes of successive beneficiaries living at the time of death of the deceased:

(1)           spouse;

(2)           children who survive the participant or who die before the participant leaving children of their own who survive the participant;

(3)           parents;

(4)           brothers and sisters who survive the participant or who die before the participant leaving children of their own who survive the participant.

If there are no members of any class of such beneficiaries, payment is made to the deceased's executors or administrators.

(B)          Allocation among Default Beneficiaries

If the same class of beneficiaries under paragraph (A) above contains two or more persons, they share equally, with further subdivision of such equal shares as next provided. In class (2), where a child dies before the participant leaving children who survive the participant, such child's share shall be subdivided equally among those children. In class (4), where a brother or sister dies before the participant leaving children who survive the participant, such brother or sister's share shall be subdivided equally among those children.

(C)          Definitions 

For purposes of this Section K4.2, "child" means a person's son or daughter by legitimate blood relationship or legal adoption; "parent" means a person's father or mother by legitimate blood relationship or legal adoption; "brother" or "sister" means another child of either or both of one's parents.

K5. Miscellaneous 

K5.1       Administration of Plan

The Plan Administrator shall be the Manager, Compensation, Benefit Plans and Policies, Human Resources Department, ExxonMobil Corporation. The Plan Administrator shall have the right and authority to conclusively interpret this Plan for all purposes, including the determination of any person’s eligibility for benefits hereunder and the resolution of any and all appeals relating to claims by participants or beneficiaries, with any such interpretation being conclusive for all participants and beneficiaries.

K5.2       Nature of Payments

Payments provided under this Plan shall be considered general obligations of the Corporation.

K5.3       Assignment or Alienation

Payments provided under this Plan may not be assigned or otherwise alienated or pledged.

K5.4       Amendment or Termination

The Corporation may at any time amend or terminate this Plan, in whole or in part, so long as the amendment does not deprive any person of the non-forfeitable right to benefits specifically granted in this Plan.

5

EX-10.(III) (C2)

 

EXHIBIT 10(iii)(c.2)

EXXONMOBIL SUPPLEMENTAL PENSION PLAN

(Including Key Employee Supplemental Pension Plan)

Effective January 1, 2015

1. Purpose 

The purpose of this Plan is to provide payments of equivalent value from the general assets of Exxon Mobil Corporation (“Corporation”) to those participants in the ExxonMobil Pension Plan (“Pension Plan”) who, because of the application of United States Internal Revenue Code (“Code”) sections 415 and 401(a)(17), are precluded from receiving from Pension Plan funded assets all the payments to which they would otherwise be entitled under the Pension Plan's formula.

2. Benefits 

2.1          Eligibility 

A person is eligible to receive benefits under this Plan only if the person satisfies any of the following requirements:

(A)          The person becomes a retiree pursuant to section 4.1(A) (relating to age, service and LTD-eligibility requirements) or section 4.1(D) (relating to retiree grow-ins in connection with certain divestments) of the ExxonMobil Common Provisions; or

(B)          The person becomes a qualified plans retiree within the meaning of the ExxonMobil Pension Plan.

2.2          Benefit Formula

(A)          In General

Except as provided in paragraph (B) below with respect to former Mobil employees, as defined in the ExxonMobil Common Provisions, (“Former Mobil Employees”), as to any Pension Plan participant eligible for payment under this Plan, the value of the payments under this Plan is an amount that when added to the normal form amount that can be paid to the participant from the Pension Plan's qualified funded assets, produces a sum equal to the total normal form amount to which the participant would be entitled computed under the Pension Plan formula applicable to that participant disregarding any reductions, restrictions, or limitations brought about by the application of Code sections 415 and 401(a)(17), reduced, but not below zero, by the following amounts:

(1)           the amount, if any, payable to the participant under the ExxonMobil Key Employee Supplemental Pension Plan, and

(2)           the amount, if any, payable to the participant under the ExxonMobil Key Employee Additional Payments Plan that is not applied as an offset against the participant's benefit under the ExxonMobil Additional Payments Plan.

Where relevant, this computation is performed after taking into account any entitlement the participant may have under the Overseas Contributory Annuity Plan. The resulting benefit is expressed in the form of a monthly five-year-certain and life annuity for the life of the participant commencing at the participant’s age 65 (“Normal Retirement Age”).

(B)          Benefit Formula for Former Mobil Employee

The payments under this Plan for Former Mobil Employees who retire with eligibility for Incentive Pension Benefits under the ExxonMobil Additional Payments Plan shall be the amounts determined under paragraph (1) below and, if applicable, paragraph (2) below.

(1)           In General

The amount benefit determined under this paragraph (1) shall be the lesser of:

(a)           the amount of the person’s benefit otherwise determined under paragraph (A) above, or

(b)           the excess if any of the person’s Overall Benefit Objective as described in section 2.3(B) of the ExxonMobil Additional Payments Plan, over the sum of the person’s benefit under the ExxonMobil Pension Plan (including any Pre-Social Security Benefit) and the person’s Incentive Pension Benefit and Nonqualified PSSP Benefit, if any, as determined under the ExxonMobil Additional Payments Plan,

expressed in the form of a monthly five-year-certain and life annuity for the life of the participant commencing at the participant’s Normal Retirement Age.

(2)           Nonqualified PSSP Benefits

1

The amount of a person’s benefit determined under this paragraph (2) shall be the amount, if any, of any Nonqualified PSSP Benefit determined for such person under the terms of the ExxonMobil Additional Payments Plan.

2.3          Offsets for Other Pension Benefits

A person’s benefit determined under section 2.2 shall be offset, but not below zero, by any benefit payable to the person under (A) an offsetting pension that is not qualified under the terms of the U.S. Internal Revenue Code, (B) a separation payment offset, or (C) a non-U.S. governmental pension offset, as such terms are defined under the ExxonMobil Pension Plan.

2.4          Plan Administrator Discretion

The procedure for calculating the benefit for former Mobil employees under section 2.2 above, and for determining the application of the offsets for other pension benefits under section 2.3 above, shall be determined in the sole and exclusive discretion of the Plan Administrator.

3. Payment of Benefits

3.1          Timing of Payment

(A)          In General

Except as provided in paragraph (B) or (C) below, payment of the benefit described in article 2 above shall occur as soon as practicable following the later to occur of the following:

(1)           the person’s retirement from ExxonMobil;

(2)           in the case of a person who, immediately prior to his or her retirement, has a Classification Level of 36 or above (“Key Employee”), the six-month anniversary of the person’s retirement;

(B)          Retirement Prior to Age 55

In the case of a person who retires from ExxonMobil on account of long-term disability prior to the first of the month in which the person attains age 55, payment of the benefit described in article 2 above shall occur on the first of the month in which the person attains age 55, or as soon as practicable thereafter.

3.2          Reduction for Early Commencement

If payments under this Plan commence prior to the month in which the person reaches Normal Retirement Age, they are reduced by applying the early commencement factors specified under the Pension Plan for a benefit commencing at the person’s then age.

3.3          Form of Payment

Payment of the benefit described in article 2 above shall be made in a lump sum that is the actuarial equivalent of the five-year-certain and life annuity calculated under section 2.2(A) or 2.2(B)(1) or the actuarial equivalent of the PSSP benefit calculated under 2.2(B)(2). For this purpose, actuarial equivalence shall be determined by the Plan Administrator using the factors and procedures that are used for the calculation of the lump-sum payment option under the Pension Plan.

3.4          Adjustment for Key Employees

If payment of a Key Employee’s benefit is delayed for six months following termination or retirement because of the requirement set out in section 3.1(A)(2) above, then instead of the lump-sum benefit calculated under section 3.3 above, the person shall receive a lump-sum benefit equal to the greater of the following:

(A)          The lump-sum payment that would otherwise have been calculated for the person under section 3.3 above as if he were not a Key Employee, based on the payment date that would have applied to the individual if he were not a Key employee and on the actuarial factors applicable as of such date under the ExxonMobil Pension Plan, plus interest for the period of delayed payment; or

(B)          A lump-sum that is the actuarial equivalent of the person’s five-year-certain and life annuity calculated as of the delayed payment date and using the actuarial factors applicable as of the six-month anniversary of the person’s retirement date.

Interest shall be credited under paragraph (A) above, at a rate equal to the Citibank prime lending rate in effect on the date the person separates from employment.

2

4. Death Benefit

4.1          Benefits Payable On Account of Death

(A)          In General

In the event a portion of a pension death benefit or a “career annuity subject to deferred commencement that commences by reason of death” that becomes payable under the terms of the Pension Plan on account of the death of a participant cannot be paid from the Pension Plan because of the application of Code sections 415 and 401(a)(17), a lump-sum death benefit of equivalent value shall be paid to the participant’s beneficiary (as determined under section 4.2 below) under this Plan. For this purpose, equivalent value shall be determined by the Plan Administrator using the factors and procedures that are used for the calculation of similar benefits under the Pension Plan.

(B)          Excluded Benefits

Neither the Qualified Joint and Survivor Annuity payment option, nor the Surviving Spouse Annuity benefit, as such are provided for under the Pension Plan, are provided as benefits under this Plan.

4.2          Designation of Beneficiaries

(A)          In General

A person may name one or more designated beneficiaries to receive the benefits payable under this Plan under section 4.1 above in the event of the person's death. Beneficiary designations shall be made in accordance with such procedures as the Plan Administrator may establish. Spousal consent to any designation is not required.

(B)          Default Beneficiaries

(1)           In General

If no specific designation is in effect, the deceased’s beneficiary is the person or persons in the first of the following classes of successive beneficiaries living at the time of death of the deceased:

(a)           spouse;

(b)           children who survive the participant or who die before the participant leaving children of their own who survive the participant;

(c)           parents;

(d)           brothers and sisters who survive the participant or who die before the participant leaving children of their own who survive the participant.

If there are no members of any class of such beneficiaries, payment is made to the deceased's executors or administrators.

(2)           Allocation among Default Beneficiaries

If the same class of beneficiaries under paragraph (1) above contains two or more persons, they share equally, with further subdivision of such equal shares as next provided. In class (b), where a child dies before the participant leaving children who survive the participant, such child's share is subdivided equally among those children. In class (d), where a brother or sister dies before the participant leaving children who survive the participant, such brother or sister's share is subdivided equally among those children.

(3)           Definitions 

For purposes of this section 4.2, "child" means a person's son or daughter by legitimate blood relationship or legal adoption; "parent" means a person's father or mother by legitimate blood relationship or legal adoption; "brother" or "sister" means another child of either or both of one's parents.

5. Miscellaneous 

5.1          Administration of Plan

The Plan Administrator shall be the Manager, Compensation, Benefit Plans and Policies, Human Resources Department, Exxon Mobil Corporation. The Plan Administrator shall have the right and authority to conclusively interpret this Plan for all purposes, including the determination of any person’s eligibility for benefits hereunder and the resolution of any and all appeals relating to claims by participants or beneficiaries, with any such interpretation being conclusive for all participants and beneficiaries.

5.2          Nature of Payments

Payments provided under this Plan are considered general obligations of the Corporation.

5.3          Assignment or Alienation

3

Except as provided in section 5.5 below, payments provided under this Plan may not be assigned or otherwise alienated or pledged.

5.4          Amendment or Termination

The Corporation reserves the right to amend or terminate this Plan, in whole or in part, including the right at any time to reduce or eliminate any accrued benefits hereunder and to alter or amend the benefit formula set out herein.

5.5          Forfeiture of Benefits

No person shall be entitled to receive payments under this Plan and any payments received under this Plan shall be forfeited and returned if it is determined by the Corporation in its sole discretion, acting through its chief executive or such person or committee as the chief executive may designate, that a person otherwise entitled to a payment under this Plan or who has commenced receiving payments under this Plan:

(A)          engaged in gross misconduct harmful to the Corporation,

(B)          committed a criminal violation harmful to the Corporation,

(C)          had concealed actions described in paragraph (A) or (B) above which would have brought about termination from employment thereby making the person ineligible for benefits under this Plan,

(D)          separated from service prior to attaining Normal Retirement Age without having received from the Corporation or its delegatee prior written approval for such termination, given in the sole discretion of the Corporation or its delegatee and in the context of recognition that benefits under this Plan would not be forfeited upon such termination, or

(E)           had been terminated for cause.

4

KEY EMPLOYEE SUPPLEMENTAL PENSION PLAN

K1. Purpose 

This Plan provides payments from the general assets of Exxon Mobil Corporation (“Corporation”) to those persons who, as of December 31, 1993,

(A)          were classified at level 36 or above,

(B)          were age 50 and above, and

(C)          were participants in the Annuity Plan of Exxon Corporation (“Annuity Plan”) and who, because of the application of United States Internal Revenue Code (“Code”) sections 415 and 401(a)(17), would have been precluded from receiving from Annuity Plan funded assets all the payments to which they would otherwise be entitled under the Annuity Plan's formula.

This Plan expresses the Corporation's commitment to provide such equivalent payments and sets forth the method for doing so.

K2. Benefits 

K2.1       Benefit Formula

As to any participant eligible for payment under this Plan, the value of such payments shall be an amount that when added to the normal form amount that could have been paid to the participant from the Annuity Plan's qualified funded assets, produces a sum equal to the total normal form amount to which the participant would have been entitled computed under the Annuity Plan formula applicable to that participant as of December 31, 1993, disregarding any reductions, restrictions, or limitations brought about by Code sections 415 and 401(a)(17). Where relevant, all computations will take into account any entitlement the participant may have under the Overseas Contributory Annuity Plan. A participant in this Plan shall have a non-forfeitable right to this amount.

K2.2       Benefit Payable On Account of Death

(A)          Death Benefit

In the event a pension death benefit is payable under the terms of the ExxonMobil Pension Plan (“Pension Plan”) on account of the death of a participant, a death benefit shall be payable under this Plan equal to the lump-sum value of the benefit that would have been payable under section K2.1 above to the participant if the participant had not died but had terminated employment and had elected to commence his or her benefit as of the date of death.

(B)          Deferred Annuity Death Benefit

In the event a “Career Annuity subject to deferred commencement that commences by reason of death” is payable under the terms of the Pension Plan on account of the death of a participant, a similar benefit shall be payable under this Plan based on the benefit that would have been payable under section K2.1 above to the participant if the participant had not died.

(C)          Calculation Methodology

The exact nature and amounts of any benefit payable under paragraph (A) or (B) shall be determined under a methodology established from time to time by the Plan Administrator.

(D)          Excluded Benefits

Specifically excluded from coverage and entitlement under this Plan are:

(1)           the legally mandated Qualified Joint and Survivor Annuity, and

(2)           the right to elect a Surviving Spouse Annuity

as such are established for married participants in the Pension Plan.

K3. Beneficiaries 

K3.1       Designation of Beneficiaries

A person entitled to receive benefits under this Plan may name one or more designated beneficiaries to receive the benefits payable under this Plan under section K2.2 above in the event of the person's death in accordance with such procedures as the Plan Administrator may establish. Spousal consent to any designation is not required.

K3.2       Default Beneficiaries

(A)          In General

If no specific designation is in effect, the deceased’s beneficiary is the person or persons in the first of the following classes of successive beneficiaries living at the time of death of the deceased:

5

(1)           spouse;

(2)           children who survive the participant or who die before the participant leaving children of their own who survive the participant;

(3)           parents;

(4)           brothers and sisters who survive the participant or who die before the participant leaving children of their own who survive the participant.

If there are no members of any class of such beneficiaries, payment is made to the deceased's executors or administrators.

(B)          Allocation among Default Beneficiaries

If the same class of beneficiaries under paragraph (A) above contains two or more persons, they share equally, with further subdivision of such equal shares as next provided. In class (2), where a child dies before the participant leaving children who survive the participant, such child's share shall be subdivided equally among those children. In class (4), where a brother or sister dies before the participant leaving children who survive the participant, such brother or sister's share shall be subdivided equally among those children.

(C)          Definitions 

For purposes of this section K3.2, "child" means a person's son or daughter by legitimate blood relationship or legal adoption; "parent" means a person's father or mother by legitimate blood relationship or legal adoption; "brother" or "sister" means another child of either or both of one's parents.

K4. Payment of Benefits

K4.1       Commencement of Benefits

(A)          In General

Payments under this Plan occur at the same time as payments under the ExxonMobil Supplemental Pension Plan commence.

(B)          Reduction for Early Commencement

If payments under this Plan commence prior to the month in which the person reaches age 65, they are reduced by applying the early commencement factors for retirees set forth in the Pension Plan for a normal maturity age of 65. For all actuarial purposes, this monthly amount paid as a five-year certain life annuity is deemed the normal form amount.

K4.2       Form of Payment

Payments under this Plan shall be made in the form of a lump sum that is the actuarial equivalent of the five-year-certain and life annuity in which the normal form of benefit is expressed. For this purpose, actuarial equivalency shall be determined by the Plan Administrator using the factors used for comparable determinations under the Pension Plan.

K5. Miscellaneous 

K5.1       Administration of Plan

The Plan Administrator shall be the Manager, Compensation, Benefit Plans and Policies, Human Resources Department, ExxonMobil Corporation. The Plan Administrator shall have the right and authority to conclusively interpret this Plan for all purposes, including the determination of any person’s eligibility for benefits hereunder and the resolution of any and all appeals relating to claims by participants or beneficiaries, with any such interpretation being conclusive for all participants and beneficiaries.

K5.2       Nature of Payments

Payments provided under this Plan shall be considered general obligations of the Corporation.

K5.3       Assignment or Alienation

Payments provided under this Plan may not be assigned or otherwise alienated or pledged.

K5.4       Amendment or Termination

The Corporation reserves the right to amend or terminate this Plan, in whole or in part, so long as the amendment does not deprive any person of the non-forfeitable right to benefits specifically granted in this Plan.

6

EX-10.(III) (F3)

 

EXHIBIT 10(iii)(f.3)

Exxon Mobil Corporation	Jeffrey J. Woodbury
5959 Las Colinas Boulevard	Vice President, Investor Relations
Irving, TX 75039	and Secretary
January 2, 2015

[Name of Non-Employee Director]

I am pleased to inform you that on January 2, 2015, you were granted 2,500 shares of restricted stock under Exxon Mobil Corporation's 2004 Non-Employee Director Restricted Stock Plan (the "Plan") and in accordance with the Board's standing resolution regarding grants under the Plan.  This letter summarizes key terms of your award and is qualified by reference to the Plan.  You should refer to the text of the Plan for a detailed description of the terms and conditions of your award.  Copies of the Plan have been previously distributed to you and are also available on request to me at any time.

The restricted stock has been registered in your name and will be held in book-entry form by the Corporation's agent during the restricted period.  As the owner of record, you have the right to vote the shares and receive cash dividends.  However, during the restricted period the shares may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and your restricted stock account will be subject to stop transfer instructions. 

The restricted period for this award began at the time of grant.  The restricted period will expire when you leave the Board after reaching retirement age (currently, age 72) or by reason of death.  If you leave the Board before reaching retirement age, your restricted stock will be forfeited unless the Board determines to lift the restrictions at that time.

If and when the restricted period expires, shares will be delivered to or for your account free of restrictions.

You are entitled to designate a beneficiary for your restricted stock account.  Please contact Jerry Miller at (972) 444-4004 for the necessary form should you wish to do so.

By accepting this award you agree to all its terms and conditions, including the restrictions on transfer and events of forfeiture.

Additional information concerning your award, including information on the tax consequences of your award and certain additional information required by the Securities Act of 1933, is also enclosed with this letter.

Any questions that you may have concerning the Plan or this award should be addressed to me.

                                                                                                                Sincerely,

                                                                                                                [signed by Jeffrey J. Woodbury]

 Enclosures 

EX-12

 

EXHIBIT 12

EXXON MOBIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
		Years Ended December 31,
		2014	2013	2012	2011	2010
		(millions of dollars)
Income from continuing operations attributable to ExxonMobil		32,520	32,580	44,880	41,060	30,460
Excess/(shortfall) of dividends over earnings of affiliates
	accounted for by the equity method	(358)	3	(1,157)	(273)	(596)
Provision for income taxes		18,015	24,263	31,045	31,051	21,561
Capitalized interest		121	148	(67)	(159)	(126)
Noncontrolling interests in earnings of consolidated subsidiaries		1,095	868	2,801	1,146	938
		51,393	57,862	77,502	72,825	52,237
Fixed Charges:
	Interest expense - borrowings	157	137	117	77	28
	Capitalized interest	344	309	506	593	532
	Rental cost representative of interest factor	618	612	640	721	709
		1,119	1,058	1,263	1,391	1,269
Total adjusted earnings available for payment of fixed charges		52,512	58,920	78,765	74,216	53,506
Number of times fixed charges are earned		46.9	55.7	62.4	53.4	42.2

EX-21

 

EXHIBIT 21

Subsidiaries of the Registrant (1), (2) and (3) – at December 31, 2014

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Abu Dhabi Petroleum Company Limited (5)	23.75	United Kingdom
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
Chalmette Refining, LLC (4) (5)	50	Delaware
Cross Timbers Energy, LLC (4) (5)	50	Delaware
Cross Timbers Energy Services, Inc.	100	Texas
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 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 Pipeline Investments Limited	100	Bahamas
Esso Raffinage	82.89	France
Esso Societe Anonyme Francaise	82.89	France
Esso (Thailand) Public Company Limited	65.99	Thailand
Esso Trading Company of Abu Dhabi	100	Delaware
Exxon Azerbaijan Limited	100	Bahamas
Exxon Chemical Arabia Inc.	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

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 Business Finance Company	100	Nevada
ExxonMobil Canada Energy	100	Canada
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 Holland B.V.	100	Netherlands
ExxonMobil Chemical Limited	100	United Kingdom
ExxonMobil China Petroleum & Petrochemical Company Limited	100	Bahamas
ExxonMobil Development Company	100	Delaware
ExxonMobil Energy Limited	100	Hong Kong
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 Global Services Company	100	Delaware
ExxonMobil Holding Company Holland LLC	100	Delaware
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 Kurdistan Region of Iraq Limited	100	Bahamas
ExxonMobil Oil Corporation	100	New York
ExxonMobil Petroleum & Chemical BVBA	100	Belgium
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
ExxonMobil Qatargas (II) Terminal Company 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 Sales and Supply LLC	100	Delaware
ExxonMobil Technology 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. (5)	50	Netherlands
Infineum USA L.P. (5)	50	Delaware
Karmorneftegaz Holding SARL (5)	33.33	Luxembourg
Mobil Australia Resources Company Pty Limited	100	Australia
Marine Well Containment Company LLC (5)	10	Delaware
McColl-Frontenac Petroleum Inc.	69.6	Canada
Mobil California Exploration & Producing Asset Company	100	Delaware
Mobil Caspian Pipeline Company	100	Delaware
Mobil Cerro Negro, Ltd.	100	Bahamas
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
Ras Laffan Liquefied Natural Gas Company Limited (5)	24.999	Qatar

3

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
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
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 (Nos. 333-72955            —        ExxonMobil Savings Plan;

                        and 333-166576)

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 25, 2015, 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 25, 2015

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 25, 2015	/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 25, 2015	/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 25, 2015	/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, 2014, 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 25, 2015	/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, 2014, 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 25, 2015	/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, 2014, 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 25, 2015	/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

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2014

Long-Term Debt [Abstract]

Summarized Long-Term Debt

			2014	2013
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	-
	Floating-rate notes due 2017 (1)		750	-
	1.819% notes due 2019		1,750	-
	Floating-rate notes due 2019 (2)		500	-
	3.176% notes due 2024		1,000	-
XTO Energy Inc. (3)
	5.000% senior notes due 2015		-	132
	5.300% senior notes due 2015		-	243
	5.650% senior notes due 2016		207	212
	6.250% senior notes due 2017		477	489
	5.500% senior notes due 2018		383	389
	6.500% senior notes due 2018		474	485
	6.100% senior notes due 2036		199	200
	6.750% senior notes due 2037		309	312
	6.375% senior notes due 2038		236	238
Mobil Producing Nigeria Unlimited (4)
	Variable notes due 2015-2019		399	742
Esso (Thailand) Public Company Ltd.(5)
	Variable notes due 2015-2019		121	177
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2015-2051 (6)			2,611	2,527
Other U.S. dollar obligations (7)			104	112
Other foreign currency obligations			9	9
Capitalized lease obligations(8)			375	375
		Total long-term debt	11,653	6,891

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

(2)Average effective interest rate of 0.4% in 2014.

(3)Includes premiums of $219 millionin 2014 and $271 million in 2013.

(4)Average effective interest rate of 4.5% in 2014 and 4.6% in 2013.

(5)Average effective interest rate of 2.4% in 2014 and 3.3% in 2013.

(6)Average effective interest rate of 0.03% in 2014 and 0.06% in 2013.

(7)Average effective interest rate of 4.2% in 2014 and 4.4% in 2013.

(8)Average imputed interest rate of 7.0% in 2014 and 7.8% in 2013.

XML

Equity Company Information (Schedule Of Equity Company Financial Summary) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Subsidiary or Equity Method Investee [Line Items]
Net assets	$ 20,017	$ 19,619	$ 18,530
ExxonMobil Share Of Equity [Member]
Subsidiary or Equity Method Investee [Line Items]
Total revenues	55,855	68,084	67,572
Income before income taxes	19,014	19,999	20,882
Income taxes	5,684	6,069	5,868
Income from equity affiliates	13,330	13,930	15,014
Current assets	16,802	19,545	18,483
Long-term assets	33,619	35,695	33,798
Total assets	50,421	55,240	52,281
Current liabilities	11,472	15,243	14,265
Long-term liabilities	19,470	20,873	19,715
Net assets	19,479	19,124	18,301
Total Equity Company Including All Owners [Member]
Subsidiary or Equity Method Investee [Line Items]
Total revenues	183,708	236,161	224,953
Income before income taxes	65,549	69,454	69,411
Income taxes	20,520	21,618	20,703
Income from equity affiliates	45,029	47,836	48,708
Current assets	49,905	62,398	59,612
Long-term assets	110,754	116,450	111,131
Total assets	160,659	178,848	170,743
Current liabilities	37,333	54,550	49,698
Long-term liabilities	66,231	68,857	68,855
Net assets	$ 57,095	$ 55,441	$ 52,190

XML

Other Comprehensive Income Information (Amounts Reclassified Out Of Acc Other Comp Income) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated Foreign Exchange Translation Adjustment [Member]
Foreign exchange translation gain/(loss) included in net income (Statement of Income line: Other Income)	$ (152)		$ 23		$ 4,352
Accumulated Defined Benefit Plans Adjustment [Member]
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	(1,571)	[1]	(2,616)	[1]	(3,621)	[1]
Accumulated Net Unrealized Investment Gain Loss [Member]
Realized change in fair value of stock investments included in net income (Statement of Income line: Other income)	$ (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.)

XML

Long-Term Debt (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt due in U.S. dollars		$ 11,341
U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies		312
Portion of long-term debt included in current liability		770	1,034
Long-term debt maturing - 2016		537
Long-term debt maturing - 2017		2,993
Long-term debt maturing - 2018		872
Long-term debt maturing - 2019		2,353
Additions to long-term debt	5,500	5,731	345	995
Long Term Financing [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Unused credit lines		$ 500

XML

Equity Company Information (Schedule Of The Corporation's Percentage Ownership Interest) (Details)	Dec. 31, 2014
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] | Chalmette Refining, LLC [Member]
Subsidiary or Equity Method Investee [Line Items]
Percentage Ownership Interest	50.00%
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 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%

XML

Pension And Other Postretirement Benefits (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate projected in 2016	4.50%
Year that rate reaches ultimate trend rate	2016
Effect of one-percentage-point increase on service and interest costs	$ 91
Effect of one-percentage-point increase on postretirement benefit obligation	1,070
Effect of one-percentage-point decrease on service and interest costs	69
Effect of one-percentage-point decrease on postretirement benefit obligation	844
Costs for defined contribution plans	$ 393	$ 392	$ 382
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%

XML

Miscellaneous Financial Information (Crude Oil, Products And Merchandise) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Miscellaneous Financial Information [Abstract]
Petroleum products	$ 4,100,000,000	$ 3,900,000,000
Crude oil	4,600,000,000	4,700,000,000
Chemical products	2,900,000,000	2,900,000,000
Gas / other	800,000,000	600,000,000
Total	$ 12,384,000,000	$ 12,117,000,000

XML

Equity Company Information (Tables)

12 Months Ended

Dec. 31, 2014

Equity Company Information [Abstract]

Schedule Of Equity Company Financial Summary

		2014			2013			2012
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		183,708		55,855	236,161		68,084	224,953		67,572
Income before income taxes		65,549		19,014	69,454		19,999	69,411		20,882
Income taxes		20,520		5,684	21,618		6,069	20,703		5,868
	Income from equity affiliates	45,029		13,330	47,836		13,930	48,708		15,014
Current assets		49,905		16,802	62,398		19,545	59,612		18,483
Long-term assets		110,754		33,619	116,450		35,695	111,131		33,798
	Total assets	160,659		50,421	178,848		55,240	170,743		52,281
Current liabilities		37,333		11,472	54,550		15,243	49,698		14,265
Long-term liabilities		66,231		19,470	68,857		20,873	68,855		19,715
	Net assets	57,095		19,479	55,441		19,124	52,190		18,301

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
Chalmette Refining, LLC	50
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 USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

XML

Pension And Other Postretirement Benefits (Benefit Obligations And Plan Assets Associated With Principal Benefit Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Medicare subsidy receipts	$ 21		$ 20
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%		5.00%
Long-term rate of compensation increase	5.75%		5.75%
Benefit obligation at January 1	17,304		19,779
Service cost	677		801		665
Interest cost	807		749		820
Defined Benefit Plan, Actuarial Net (Gains) Losses	3,192		(1,520)
Amendments, divestments and other	(24)		15
Benefit obligation at December 31	20,529		17,304		19,779
Accumulated benefit obligation at December 31	16,385		13,989
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.10%		4.30%
Long-term rate of compensation increase	5.30%		5.40%
Benefit obligation at January 1	27,357		28,670
Service cost	590		697		648
Interest cost	1,138		1,076		1,145
Defined Benefit Plan, Actuarial Net (Gains) Losses	4,929		(1,454)
Foreign exchange rate changes	(2,540)		(284)
Amendments, divestments and other	(61)		(37)
Benefit obligation at December 31	30,047		27,357		28,670
Accumulated benefit obligation at December 31	26,318		23,949
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%		5.00%
Long-term rate of compensation increase	5.75%		5.75%
Benefit obligation at January 1	7,868		9,058
Service cost	140		176		134
Interest cost	383		352		380
Defined Benefit Plan, Actuarial Net (Gains) Losses	1,522		(1,267)
Foreign exchange rate changes	(48)		(43)
Amendments, divestments and other	96		103
Benefit obligation at December 31	9,436		7,868		9,058
Benefit Payments For Funded And Unfunded Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	(1,427)	[1]	(2,520)	[1]
Benefit Payments For Funded And Unfunded Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	(1,366)	[1]	(1,311)	[1]
Benefit Payments For Funded And Unfunded Plans [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	$ (525)	[1],[2]	$ (511)	[1],[2]

[1] Benefit payments for funded and unfunded plans.

[2] For 2014 and 2013, other postretirement benefits paid are net of $21 million and $20 million of Medicare subsidy receipts, respectively.

XML

Incentive Program (Summary Of Restricted Stock And Units Outstanding) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Incentive Program [Abstract]
Issued and outstanding at January 1, Restricted stock, Shares	45,207
2013 award issued in 2014, Shares	9,705
Vested, Shares	(10,286)
Forfeited, Shares	(187)
Issued and outstanding at December 31, Restricted stock, Shares	44,439
Issued and outstanding at January 1, Weighted Average Grant-Date Fair Value per Share	$ 78.29
2013 award issued in 2014, Weighted Average Grant-Date Fair Value per Share	$ 94.47
Vested, Weighted Average Grant-Date Fair Value per Share	$ 79.89
Forfeited, Weighted Average Grant-Date Fair Value per Share	$ 78.89
Issued and outstanding at December 31, Weighted Average Grant-Date Fair Value per Share	$ 81.45

XML

Pension And Other Postretirement Benefits (Estimated Amortization) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	$ 1,001	[1]
Prior service cost	6	[2]
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	753	[1]
Prior service cost	105	[2]
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss/(gain)	211	[1]
Prior service cost	$ 14	[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.

XML

Property, Plant And Equipment And Asset Retirement Obligations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Accumulated depreciation and depletion	$ 194,121	$ 190,867
Interest capitalized	$ 344	$ 309	$ 506
Downstream [Member] | Refinery And Lubes Basestock Manufacturing Facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years	25 years 0 months 0 days
Downstream [Member] | Service Station Buildings And Fixed Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years	20 years 0 months 0 days
Chemical [Member] | Investments In Process Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of equipment, years	20 years 0 months 0 days

XML

Litigation And Other Contingencies (Schedule Of Guarantees) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Loss Contingencies [Line Items]
Guarantees	$ 10,449
Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	6,426	[1]
Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	4,023
Debt-Related Guarantees [Member]
Loss Contingencies [Line Items]
Guarantees	3,547
Debt-Related Guarantees [Member] | Papua New Guinea Liquefied Natural Gas Project [Member]
Loss Contingencies [Line Items]
Guarantees	3,400
Debt-Related Guarantees [Member] | Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	3,506	[1]
Debt-Related Guarantees [Member] | Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	41
Other Guarantees [Member]
Loss Contingencies [Line Items]
Guarantees	6,902
Other Guarantees [Member] | Equity Company Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	2,920	[1]
Other Guarantees [Member] | Other Third-Party Obligations [Member]
Loss Contingencies [Line Items]
Guarantees	$ 3,982

[1] ExxonMobil share

XML

Pension And Other Postretirement Benefits (Fair Value Of Benefit Plan Assets - Other Postretirement) (Details) (Other Postretirement Benefit Plans Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 468		$ 620		$ 581
U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	106		157
Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	75		149
Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		9
Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103		129
Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171		168
Asset Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9		4
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		4
Fair Value Inputs Level2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	466		611
Fair Value Inputs Level2 [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	106	[1]	157	[1]
Fair Value Inputs Level2 [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	75	[1]	149	[1]
Fair Value Inputs Level2 [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	103	[2]	129	[2]
Fair Value Inputs Level2 [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	171	[2]	168	[2]
Fair Value Inputs Level2 [Member] | Asset Backed Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9	[2]	4	[2]
Fair Value Inputs Level2 [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		4
Fair Value Inputs Level3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2		9
Fair Value Inputs Level3 [Member] | Private Equity Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 2	[3]	$ 9	[3]

[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.

XML

Pension And Other Postretirement Benefits (Summary Of Assets In Excess Of/(Less Than) Benefit Obligation) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Funded Status of Plan	$ (4,590)		$ (3,547)
Unfunded plans	(3,024)		(2,567)
Total	(7,614)	[1]	(6,114)	[1]
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Funded Status of Plan	(2,113)		(941)
Unfunded plans	(7,839)		(7,133)
Total	$ (9,952)	[1]	$ (8,074)	[1]

[1] Fair value of assets less benefit obligation shown on the preceding page.

XML

Pension And Other Postretirement Benefits (Change In The Fair Value Of Level 3 Assets) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits - U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	$ 523	$ 489
Net realized gains/(losses)	2	(1)
Net unrealized gains/(losses)	89	86
Net purchases/(sales)	(52)	(51)
Fair value at December 31	562	523
Pension Benefits - Non-U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	502	448
Net realized gains/(losses)	23	11
Net unrealized gains/(losses)	31	57
Net purchases/(sales)	(21)	(14)
Fair value at December 31	535	502
Pension Benefits - Non-U.S. [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	136	293
Net realized gains/(losses)	(17)	(13)
Net unrealized gains/(losses)	8	10
Net purchases/(sales)	(70)	(154)
Fair value at December 31	57	136
Other Postretirement Benefits [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	9	7
Net unrealized gains/(losses)		3
Net purchases/(sales)	(7)	(1)
Fair value at December 31	$ 2	$ 9

XML

Litigation And Other Contingencies (Schedule Of Unconditional Purchase Obligations) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	$ 150
2016-2019	608
2020 and Beyond	337
Total	1,095	[1]
Present value of these commitments	927
Undiscounted unconditional purchase obligations	1,095	[1]
Imputed interest	168
Equity Company Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	433
Undiscounted unconditional purchase obligations	$ 433

[1] Undiscounted obligations of $1,095 million mainly pertain to pipeline throughput agreements and include $433 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $168 million, totaled $927 million.

XML

Long-Term Debt (Summarized Long-Term Debt) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument, Unamortized Premium	$ 219		$ 271
Long-term debt	11,653		6,891
Combined Exxon Mobil And Affiliates [Member] | Other U.S. Dollar Obligations [Member]
Other long-term debt	104	[1]	112	[1]
Average effective interest rate	4.20%		4.40%
Combined Exxon Mobil And Affiliates [Member] | Other Foreign Currency Obligations [Member]
Other long-term debt	9		9
0.921% Notes Due 2017 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	1,500
Interest rate	0.921%
Debt maturity	Mar. 15, 2017
Floating-Rate Notes Due 2017 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	750	[2]
Debt maturity	Mar. 15, 2017
Average effective interest rate	0.30%
1.819% Notes Due 2019 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	1,750
Interest rate	1.819%
Debt maturity	Mar. 15, 2019
Floating-Rate Notes Due 2019 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	500	[3]
Debt maturity	Mar. 15, 2019
Average effective interest rate	0.40%
3.176% Notes Due 2024 [Member] | Exxon Mobil Corporation [Member] | Other U.S. Dollar Obligations [Member]
Senior notes, noncurrent	1,000
Interest rate	3.176%
Debt maturity	Mar. 15, 2024
5.000% Senior Notes Due 2015 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent			132
Interest rate			5.00%
Debt maturity			Jan. 31, 2015
5.300% Senior Notes Due 2015 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent			243
Interest rate			5.30%
Debt maturity			Jun. 30, 2015
5.650% Senior Notes Due 2016 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	207		212
Interest rate	5.65%
Debt maturity	Apr. 01, 2016		Apr. 01, 2016
6.250% Senior Notes Due 2017 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	477		489
Interest rate	6.25%
Debt maturity	Aug. 01, 2017		Aug. 01, 2017
5.500% Senior Notes Due 2018 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	383		389
Interest rate	5.50%
Debt maturity	Jun. 15, 2018		Jun. 15, 2018
6.500% Senior Notes Due 2018 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	474		485
Interest rate	6.50%
Debt maturity	Dec. 15, 2018		Dec. 15, 2018
6.100% Senior Notes Due 2036 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	199		200
Interest rate	6.10%
Debt maturity	Apr. 01, 2036		Apr. 01, 2036
6.750% Senior Notes Due 2037 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	309		312
Interest rate	6.75%
Debt maturity	Aug. 01, 2037		Aug. 01, 2037
6.375% Senior Notes Due 2038 [Member] | XTO Energy Inc. [Member]
Senior notes, noncurrent	236		238
Interest rate	6.375%
Debt maturity	Jun. 15, 2038		Jun. 15, 2038
Variable Notes Due 2015-2019 [Member] | Mobil Producing Nigeria Unlimited [Member]
Senior notes, noncurrent	399	[4]	742	[4]
Debt Instrument, maturity date range, start	Jun. 15, 2016		Dec. 31, 2017
Debt Instrument, maturity date range, end	Mar. 15, 2019		Dec. 31, 2019
Average effective interest rate	4.50%		4.60%
Variable Notes Due 2015-2019 [Member] | Esso (Thailand) Public Company Ltd. [Member]
Senior notes, noncurrent	121	[5]	177	[5]
Debt Instrument, maturity date range, start	Nov. 30, 2017		Sep. 28, 2015
Debt Instrument, maturity date range, end	Dec. 31, 2019		Nov. 30, 2017
Average effective interest rate	2.40%		3.30%
Debentures Due 2021 [Member] | Mobil Corporation [Member]
Other long-term debt	249		249
Interest rate	8.625%
Debt maturity	Aug. 15, 2021		Aug. 15, 2021
Industrial Revenue Bonds Due 2015-2051 [Member] | Combined Exxon Mobil And Affiliates [Member]
Other long-term debt	2,611	[6]	2,527	[6]
Debt Instrument, maturity date range, start	Apr. 01, 2017		Jul. 31, 2015
Debt Instrument, maturity date range, end	Dec. 01, 2051		Dec. 01, 2051
Average effective interest rate	0.03%		0.06%
Capitalized Lease Obligations [Member] | Combined Exxon Mobil And Affiliates [Member]
Average effective interest rate	7.00%		7.80%
Long-term debt	$ 375	[7]	$ 375	[7]

[1] Average effective interest rate of 4.2% in 2014 and 4.4% in 2013.

[2] Average effective interest rate of 0.3% in 2014.

[3] Average effective interest rate of 0.4% in 2014.

[4] Average effective interest rate of 4.5% in 2014 and 4.6% in 2013.

[5] Average effective interest rate of 2.4% in 2014 and 3.3% in 2013.

[6] Average effective interest rate of 0.03% in 2014 and 0.06% in 2013.

[7] Average imputed interest rate of 7.0% in 2014 and 7.8% in 2013.

XML

Pension And Other Postretirement Benefits

12 Months Ended

Dec. 31, 2014

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
		2014	2013	2014	2013	2014	2013
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.00	5.00	3.10	4.30	4.00	5.00
	Long-term rate of compensation increase	5.75	5.75	5.30	5.40	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	17,304	19,779	27,357	28,670	7,868	9,058
	Service cost	677	801	590	697	140	176
	Interest cost	807	749	1,138	1,076	383	352
	Actuarial loss/(gain)	3,192	(1,520)	4,929	(1,454)	1,522	(1,267)
	Benefits paid (1) (2)	(1,427)	(2,520)	(1,366)	(1,311)	(525)	(511)
	Foreign exchange rate changes	-	-	(2,540)	(284)	(48)	(43)
	Amendments, divestments and other	(24)	15	(61)	(37)	96	103
Benefit obligation at December 31		20,529	17,304	30,047	27,357	9,436	7,868
Accumulated benefit obligation at December 31		16,385	13,989	26,318	23,949	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2014 and 2013, other postretirement benefits paid are net of $21 million and $20 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 2016 and subsequent years. A one-percentage-point increase in thehealth care cost trend rate would increase service and interest cost by $91 million and the postretirement benefit obligation by $1,070 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $69 million and the postretirement benefit obligation by $844 million.

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Change in plan assets
	Fair value at January 1	11,190	12,632	19,283	18,090	620	581
	Actual return on plan assets	1,497	617	3,153	1,604	41	64
	Foreign exchange rate changes	-	-	(1,738)	(270)	-	-
	Company contribution	1,476	101	554	919	31	35
	Benefits paid(1)	(1,248)	(2,171)	(912)	(869)	(224)	(60)
	Other	-	11	(245)	(191)	-	-
Fair value at December 31		12,915	11,190	20,095	19,283	468	620

(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.
		2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(4,590)	(3,547)	(2,113)	(941)
	Unfunded plans	(3,024)	(2,567)	(7,839)	(7,133)
Total		(7,614)	(6,114)	(9,952)	(8,074)

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
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31 (1)	(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	1	302	201	-	-
	Current liabilities	(340)	(275)	(325)	(358)	(369)	(359)
	Postretirement benefits reserves	(7,274)	(5,840)	(9,929)	(7,917)	(8,599)	(6,889)
Total recorded		(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,589	4,780	9,642	7,943	2,997	1,603
	Prior service cost	27	60	429	665	51	65
Total recorded in accumulated other
	comprehensive income	6,616	4,840	10,071	8,608	3,048	1,668

(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
				2014	2013	2012	2014	2013	2012	2014	2013	2012
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31		(percent)
	Discount rate			5.00	4.00	5.00	4.30	3.80	4.00	5.00	4.00	5.00
	Long-term rate of return on funded assets			7.25	7.25	7.25	6.30	6.40	6.60	7.25	7.25	7.25
	Long-term rate of compensation increase			5.75	5.75	5.75	5.40	5.50	5.40	5.75	5.75	5.75
Components of net periodic benefit cost				(millions of dollars)
	Service cost			677	801	665	590	697	648	140	176	134
	Interest cost			807	749	820	1,138	1,076	1,145	383	352	380
	Expected return on plan assets			(799)	(835)	(789)	(1,193)	(1,128)	(1,109)	(37)	(41)	(38)
	Amortization of actuarial loss/(gain)			409	646	576	628	852	844	116	228	170
	Amortization of prior service cost			8	7	7	120	117	117	14	21	34
	Net pension enhancement and
	curtailment/settlement cost(1)			276	723	333	-	22	1,540	-	-	-
Net periodic benefit cost				1,378	2,091	1,612	1,283	1,636	3,185	616	736	680
	(1)	Non-U.S. net pension enhancement and curtailment/settlement cost for 2012 includes $1,420 million (on a consolidated-company, before-tax basis) of accumulated other comprehensive income for the postretirement benefit reserves adjustment that was recycled into earnings and included in the Japan restructuring gain reported in “Other income”.
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)			2,494	(1,302)	1,885	2,969	(1,938)	1,906	1,518	(1,290)	1,008
	Amortization of actuarial (loss)/gain			(685)	(1,369)	(909)	(628)	(874)	(2,384)	(116)	(228)	(170)
	Prior service cost/(credit)			(25)	-	-	(70)	30	71	-	-	-
	Amortization of prior service (cost)/credit			(8)	(7)	(7)	(120)	(117)	(117)	(14)	(21)	(34)
	Foreign exchange rate changes			-	-	-	(688)	(155)	271	(8)	(10)	3
Total recorded in other comprehensive income				1,776	(2,678)	969	1,463	(3,054)	(253)	1,380	(1,549)	807
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax			3,154	(587)	2,581	2,746	(1,418)	2,932	1,996	(813)	1,487

Costs for defined contribution plans were $393million, $392 million and $382 million in 2014, 2013 and 2012, respectively.

A summary of the change in accumulated other comprehensive income is shown in the table below:

		Total Pension and
		Other Postretirement Benefits
		2014	2013	2012
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	(1,776)	2,678	(969)
	Non-U.S. pension	(1,463)	3,054	253
	Other postretirement benefits	(1,380)	1,549	(807)
Total (charge)/credit to other comprehensive income, before tax		(4,619)	7,281	(1,523)
(Charge)/credit to income tax (see Note 4)		1,549	(2,336)	393
(Charge)/credit to investment in equity companies		(81)	49	(49)
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	(3,151)	4,994	(1,179)
Charge/(credit) to equity of noncontrolling interests		85	(279)	(124)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		(3,066)	4,715	(1,303)

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset 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 for the non-U.S. plans in aggregate 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 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:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		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:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(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

• 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.
• For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
• 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

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

			U.S. Pension									Non-U.S. Pension
			Fair Value Measurement									Fair Value Measurement
			at December 31, 2013, Using:									at December 31, 2013, Using:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-		2,514	(1)		-		2,514		-			3,046	(1)		-		3,046
		Non-U.S.		-		2,622	(1)		-		2,622		294	(2)		5,608	(1)		-		5,902
	Private equity			-		-			523	(3)	523		-			-			502	(3)	502
	Debt securities
		Corporate		-		3,430	(4)		-		3,430		-			2,125	(4)		-		2,125
		Government		-		2,056	(4)		-		2,056		272	(5)		7,100	(4)		-		7,372
		Asset-backed		-		6	(4)		-		6		-			103	(4)		-		103
	Real estate funds			-		-			-		-		-			-			136	(6)	136
	Cash			-		27	(7)		-		27		57			20	(8)		-		77
Total at fair value				-		10,655			523		11,178		623			18,002			638		19,263
	Insurance contracts
		at contract value									12										20
Total plan assets											11,190										19,283

(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, 2013, Using:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(Level 1)	(Level 2)		(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	157	(1)	-		157
		Non-U.S.		-	149	(1)	-		149
	Private equity			-	-		9	(2)	9
	Debt securities
		Corporate		-	129	(3)	-		129
		Government		-	168	(3)	-		168
		Asset-backed		-	4	(3)	-		4
	Cash			-	4		-		4
Total at fair value				-	611		9		620

(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 2013 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

	2013
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	489	448	293	7
Net realized gains/(losses)	(1)	11	(13)	-
Net unrealized gains/(losses)	86	57	10	3
Net purchases/(sales)	(51)	(14)	(154)	(1)
Fair value at December 31	523	502	136	9

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.
			2014	2013		2014	2013
		(millions of dollars)
For funded pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		17,505	14,737		5,031	891
	Accumulated benefit obligation		14,493	12,342		4,590	689
	Fair value of plan assets		12,915	11,189		3,890	611
For unfunded pension plans:
	Projected benefit obligation		3,024	2,567		7,839	7,133
	Accumulated benefit obligation		1,892	1,647		6,573	6,070

					Other
		Pension Benefits			Postretirement
		U.S.		Non-U.S.	Benefits
		(millions of dollars)
Estimated 2015 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain) (1)		1,001	753		211
	Prior service cost (2)		6	105		14

(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 2015		-	560	-		-
Benefit payments expected in:
	2015	1,628	1,194	467		24
	2016	1,554	1,213	479		25
	2017	1,529	1,278	490		26
	2018	1,445	1,298	499		28
	2019	1,410	1,339	507		29
	2020 - 2024	6,714	6,988	2,613		172

XML

Cash Flow Information (Cash Payments For Interest And Income Taxes) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flow Information [Abstract]
Cash payments for interest	$ 380	$ 426	$ 555
Cash payments for income taxes	18,085	25,066	24,349
Asset exchanges, primarily noncash	$ 1,200		$ 1,000

XML

Pension And Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2014

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
		2014	2013	2014	2013	2014	2013
		(percent)
Weighted-average assumptions used to determine
	benefit obligations at December 31
	Discount rate	4.00	5.00	3.10	4.30	4.00	5.00
	Long-term rate of compensation increase	5.75	5.75	5.30	5.40	5.75	5.75
		(millions of dollars)
Change in benefit obligation
	Benefit obligation at January 1	17,304	19,779	27,357	28,670	7,868	9,058
	Service cost	677	801	590	697	140	176
	Interest cost	807	749	1,138	1,076	383	352
	Actuarial loss/(gain)	3,192	(1,520)	4,929	(1,454)	1,522	(1,267)
	Benefits paid (1) (2)	(1,427)	(2,520)	(1,366)	(1,311)	(525)	(511)
	Foreign exchange rate changes	-	-	(2,540)	(284)	(48)	(43)
	Amendments, divestments and other	(24)	15	(61)	(37)	96	103
Benefit obligation at December 31		20,529	17,304	30,047	27,357	9,436	7,868
Accumulated benefit obligation at December 31		16,385	13,989	26,318	23,949	-	-

(1)Benefit payments for funded and unfunded plans.

(2)For 2014 and 2013, other postretirement benefits paid are net of $21 million and $20 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
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Change in plan assets
	Fair value at January 1	11,190	12,632	19,283	18,090	620	581
	Actual return on plan assets	1,497	617	3,153	1,604	41	64
	Foreign exchange rate changes	-	-	(1,738)	(270)	-	-
	Company contribution	1,476	101	554	919	31	35
	Benefits paid(1)	(1,248)	(2,171)	(912)	(869)	(224)	(60)
	Other	-	11	(245)	(191)	-	-
Fair value at December 31		12,915	11,190	20,095	19,283	468	620

(1) Benefit payments for funded plans.

Summary Of Assets In Excess Of/(Less Than) Benefit Obligation

		Pension Benefits
		U.S.		Non-U.S.
		2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31
	Funded plans	(4,590)	(3,547)	(2,113)	(941)
	Unfunded plans	(3,024)	(2,567)	(7,839)	(7,133)
Total		(7,614)	(6,114)	(9,952)	(8,074)

Amounts Recorded In Balance Sheet And Other Comprehensive Income

		Pension Benefits				Other Postretirement
		U.S.		Non-U.S.		Benefits
		2014	2013	2014	2013	2014	2013
		(millions of dollars)
Assets in excess of/(less than) benefit obligation
	Balance at December 31 (1)	(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in the consolidated balance
	sheet consist of:
	Other assets	-	1	302	201	-	-
	Current liabilities	(340)	(275)	(325)	(358)	(369)	(359)
	Postretirement benefits reserves	(7,274)	(5,840)	(9,929)	(7,917)	(8,599)	(6,889)
Total recorded		(7,614)	(6,114)	(9,952)	(8,074)	(8,968)	(7,248)
Amounts recorded in accumulated other
	comprehensive income consist of:
	Net actuarial loss/(gain)	6,589	4,780	9,642	7,943	2,997	1,603
	Prior service cost	27	60	429	665	51	65
Total recorded in accumulated other
	comprehensive income	6,616	4,840	10,071	8,608	3,048	1,668

(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
				2014	2013	2012	2014	2013	2012	2014	2013	2012
Weighted-average assumptions used to
	determine net periodic benefit cost for
	years ended December 31		(percent)
	Discount rate			5.00	4.00	5.00	4.30	3.80	4.00	5.00	4.00	5.00
	Long-term rate of return on funded assets			7.25	7.25	7.25	6.30	6.40	6.60	7.25	7.25	7.25
	Long-term rate of compensation increase			5.75	5.75	5.75	5.40	5.50	5.40	5.75	5.75	5.75
Components of net periodic benefit cost				(millions of dollars)
	Service cost			677	801	665	590	697	648	140	176	134
	Interest cost			807	749	820	1,138	1,076	1,145	383	352	380
	Expected return on plan assets			(799)	(835)	(789)	(1,193)	(1,128)	(1,109)	(37)	(41)	(38)
	Amortization of actuarial loss/(gain)			409	646	576	628	852	844	116	228	170
	Amortization of prior service cost			8	7	7	120	117	117	14	21	34
	Net pension enhancement and
	curtailment/settlement cost(1)			276	723	333	-	22	1,540	-	-	-
Net periodic benefit cost				1,378	2,091	1,612	1,283	1,636	3,185	616	736	680
	(1)	Non-U.S. net pension enhancement and curtailment/settlement cost for 2012 includes $1,420 million (on a consolidated-company, before-tax basis) of accumulated other comprehensive income for the postretirement benefit reserves adjustment that was recycled into earnings and included in the Japan restructuring gain reported in “Other income”.
Changes in amounts recorded in accumulated
	other comprehensive income:
	Net actuarial loss/(gain)			2,494	(1,302)	1,885	2,969	(1,938)	1,906	1,518	(1,290)	1,008
	Amortization of actuarial (loss)/gain			(685)	(1,369)	(909)	(628)	(874)	(2,384)	(116)	(228)	(170)
	Prior service cost/(credit)			(25)	-	-	(70)	30	71	-	-	-
	Amortization of prior service (cost)/credit			(8)	(7)	(7)	(120)	(117)	(117)	(14)	(21)	(34)
	Foreign exchange rate changes			-	-	-	(688)	(155)	271	(8)	(10)	3
Total recorded in other comprehensive income				1,776	(2,678)	969	1,463	(3,054)	(253)	1,380	(1,549)	807
Total recorded in net periodic benefit cost and
	other comprehensive income, before tax			3,154	(587)	2,581	2,746	(1,418)	2,932	1,996	(813)	1,487

Summary Of Change In Accumulated Other Comprehensive Income

		Total Pension and
		Other Postretirement Benefits
		2014	2013	2012
		(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
	U.S. pension	(1,776)	2,678	(969)
	Non-U.S. pension	(1,463)	3,054	253
	Other postretirement benefits	(1,380)	1,549	(807)
Total (charge)/credit to other comprehensive income, before tax		(4,619)	7,281	(1,523)
(Charge)/credit to income tax (see Note 4)		1,549	(2,336)	393
(Charge)/credit to investment in equity companies		(81)	49	(49)
(Charge)/credit to other comprehensive income including noncontrolling
	interests, after tax	(3,151)	4,994	(1,179)
Charge/(credit) to equity of noncontrolling interests		85	(279)	(124)
(Charge)/credit to other comprehensive income attributable to ExxonMobil		(3,066)	4,715	(1,303)

Fair Value Of The Benefit Plan Assets (Pension)

			U.S. Pension									Non-U.S. Pension
			Fair Value Measurement									Fair Value Measurement
			at December 31, 2014, Using:									at December 31, 2014, Using:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		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.

			U.S. Pension									Non-U.S. Pension
			Fair Value Measurement									Fair Value Measurement
			at December 31, 2013, Using:									at December 31, 2013, Using:
				Quoted									Quoted
				Prices									Prices
				in Active	Significant								in Active		Significant
			Markets for			Other		Significant				Markets for				Other		Significant
				Identical	Observable			Unobservable					Identical		Observable			Unobservable
				Assets		Inputs			Inputs				Assets			Inputs			Inputs
				(Level 1)		(Level 2)			(Level 3)		Total		(Level 1)			(Level 2)			(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-		2,514	(1)		-		2,514		-			3,046	(1)		-		3,046
		Non-U.S.		-		2,622	(1)		-		2,622		294	(2)		5,608	(1)		-		5,902
	Private equity			-		-			523	(3)	523		-			-			502	(3)	502
	Debt securities
		Corporate		-		3,430	(4)		-		3,430		-			2,125	(4)		-		2,125
		Government		-		2,056	(4)		-		2,056		272	(5)		7,100	(4)		-		7,372
		Asset-backed		-		6	(4)		-		6		-			103	(4)		-		103
	Real estate funds			-		-			-		-		-			-			136	(6)	136
	Cash			-		27	(7)		-		27		57			20	(8)		-		77
Total at fair value				-		10,655			523		11,178		623			18,002			638		19,263
	Insurance contracts
		at contract value									12										20
Total plan assets											11,190										19,283

(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, 2014, Using:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(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

• 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.
• For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
• 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, 2013, Using:
				Quoted
				Prices
				in Active	Significant
				Markets for	Other		Significant
				Identical	Observable		Unobservable
				Assets	Inputs		Inputs
				(Level 1)	(Level 2)		(Level 3)		Total
			(millions of dollars)
Asset category:
	Equity securities
		U.S.		-	157	(1)	-		157
		Non-U.S.		-	149	(1)	-		149
	Private equity			-	-		9	(2)	9
	Debt securities
		Corporate		-	129	(3)	-		129
		Government		-	168	(3)	-		168
		Asset-backed		-	4	(3)	-		4
	Cash			-	4		-		4
Total at fair value				-	611		9		620

(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

	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

	2013
	Pension			Other
	U.S.	Non-U.S.		Postretirement
	Private	Private	Real	Private
	Equity	Equity	Estate	Equity
	(millions of dollars)
Fair value at January 1	489	448	293	7
Net realized gains/(losses)	(1)	11	(13)	-
Net unrealized gains/(losses)	86	57	10	3
Net purchases/(sales)	(51)	(14)	(154)	(1)
Fair value at December 31	523	502	136	9

Pension Plans With Accumulated Benefit Obligation In Excess Of Plan Assets

		Pension Benefits
		U.S.			Non-U.S.
			2014	2013		2014	2013
		(millions of dollars)
For funded pension plans with an accumulated benefit obligation
	in excess of plan assets:
	Projected benefit obligation		17,505	14,737		5,031	891
	Accumulated benefit obligation		14,493	12,342		4,590	689
	Fair value of plan assets		12,915	11,189		3,890	611
For unfunded pension plans:
	Projected benefit obligation		3,024	2,567		7,839	7,133
	Accumulated benefit obligation		1,892	1,647		6,573	6,070

Estimated Next Year Amortization

					Other
		Pension Benefits			Postretirement
		U.S.		Non-U.S.	Benefits
		(millions of dollars)
Estimated 2015 amortization from accumulated other comprehensive income:
	Net actuarial loss/(gain) (1)		1,001	753		211
	Prior service cost (2)		6	105		14

(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 2015		-	560	-		-
Benefit payments expected in:
	2015	1,628	1,194	467		24
	2016	1,554	1,213	479		25
	2017	1,529	1,278	490		26
	2018	1,445	1,298	499		28
	2019	1,410	1,339	507		29
	2020 - 2024	6,714	6,988	2,613		172

XML

Litigation And Other Contingencies (Narrative) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014	Oct. 09, 2014	Jun. 27, 2007	May 01, 2007	Oct. 24, 2011
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
Recognized earnings net of the remaining asset value from earlier ICC award	269,000,000
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

XML

Income, Sales-Based And Other Taxes (Reconciliation Between Income Tax Expense And Theoretical U.S. Tax) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income, Sales-Based And Other Taxes [Abstract]
United States Income before income taxes	$ 9,080	$ 9,746	$ 11,222
Non-U.S. Income before income taxes	42,550	47,965	67,504
Income before income taxes	51,630	57,711	78,726
Theoretical tax	18,071	20,199	27,554
Effect of equity method of accounting	(4,663)	(4,874)	(5,254)
Non-U.S. taxes in excess of theoretical U.S. tax	5,442	10,528	8,434
U.S. tax on non-U.S. operations	5	37	89
State taxes, net of federal tax benefit	(324)	258	391
Other	(516)	(1,885)	(169)
Total income tax expense	18,015	24,263	31,045
ExxonMobil share of equity company income taxes	5,678	6,061	5,859
Total income taxes	23,693	30,324	36,904
Net income including noncontrolling interests	33,615	33,448	47,681
Total income before taxes	$ 57,308	$ 63,772	$ 84,585
Effective income tax rate	41.00%	48.00%	44.00%

XML

Leased Facilities (Tables)

12 Months Ended

Dec. 31, 2014

Leased Facilities [Abstract]

Leased Facilities

		Related
	Lease Payments	Sublease
	Under Minimum	Rental
	Commitments	Income
	(millions of dollars)
2015	2,034	31
2016	1,379	7
2017	774	6
2018	418	3
2019	312	3
2020 and beyond	1,296	20
Total	6,213	70

Net Rental Cost

	2014	2013	2012
	(millions of dollars)
Rental cost	4,077	3,841	3,851
Less sublease rental income	52	44	44
Net rental cost	4,025	3,797	3,807

XML

Additional Working Capital Information (Schedule Of Notes, Accounts Receivable And Payable, Loans Payable, Accrued Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Additional Working Capital Information [Abstract]
Trade notes and accounts receivable, less reserves of $113 million and $112 million	$ 18,541	$ 25,993
Other notes and accounts receivable, less reserves of $48 million and $28 million	9,468	7,159
Total notes and accounts receivable	28,009	33,152
Bank loans	473	723
Commercial paper	16,225	14,051
Long-term debt due within one year	770	1,034
Total notes and loans payable	17,468	15,808
Trade payables	25,286	30,920
Payables to equity companies	6,589	6,587
Accrued taxes other than income taxes	3,290	3,883
Other accounts payable and accrued liabilities	7,062	6,695
Total accounts payable and accrued liabilities	42,227	48,085
Trade notes and accounts receivable, reserves	113	112
Other notes and accounts receivable, reserves	$ 48	$ 28

XML

Leased Facilities (Net Rental Cost) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leased Facilities [Abstract]
Rental cost	$ 4,077	$ 3,841	$ 3,851
Less sublease rental income	52	44	44
Net rental cost	$ 4,025	$ 3,797	$ 3,807

XML

Accounting For Suspended Exploratory Well Costs (Change In Capitalized Suspended Exploratory Well Costs) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting For Suspended Exploratory Well Costs [Abstract]
Capitalized suspended exploratory well costs, beginning balance	$ 2,707	$ 2,679	$ 2,881
Additions pending the determination of proved reserves	1,095	293	868
Charged to expense	(28)	(52)	(95)
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(160)	(107)	(631)
Divestments/Other	(27)	(106)	(344)
Capitalized suspended exploratory well costs, ending balance	3,587	2,707	2,679
Ending balance attributed to equity companies included above	$ 645	$ 13	$ 3

XML

Other Comprehensive Income Information (Schedule of Accumulated Other Comprehensive Income Information) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current period change excluding amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	$ (5,847)	$ (3,620)	$ 920
Amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	152	(23)	(4,352)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	(4,262)	3,174	(3,574)
Amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	1,111	1,820	2,395
Current period change excluding amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	(63)
Amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	3
Beginning Balance, Total	(10,725)
Total other comprehensive income	(8,906)	1,351	(4,611)
Ending Balance, Total	(18,957)	(10,725)
Exxon Mobil Corporation Share After Noncontrolling Interest [Member]
Beginning Balance, Cumulative Foreign Exchange Translation Adjustment	(846)	2,410	4,168
Current period change excluding amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(5,258)	(3,233)	842
Amounts reclassified from accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	152	(23)	(2,600)
Total change in accumulated other comprehensive income, Cumulative Foreign Exchange Translation Adjustment	(5,106)	(3,256)	(1,758)
Ending Balance, Cumulative Foreign Exchange Translation Adjustment	(5,952)	(846)	2,410
Beginning Balance, Postretirement Benefits Reserves Adjustment	(9,879)	(14,594)	(13,291)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	(4,132)	2,963	(3,402)
Amounts reclassified from accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	1,066	1,752	2,099
Total change in accumulated other comprehensive income, Postretirement Benefits Reserves Adjustment	(3,066)	4,715	(1,303)
Ending Balance, Postretirement Benefits Reserves Adjustment	(12,945)	(9,879)	(14,594)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	(63)
Amounts reclassified from accumulated other comprehensive income, Unrealized Change in Stock Investments	3
Total change in accumulated other comprehensive income, Unrealized Change in Stock Investments	(60)
Ending Balance, Unrealized Change in Stock Investments	(60)
Beginning Balance, Total	(10,725)	(12,184)	(9,123)
Current period change excluding amounts reclassified from accumulated other comprehensive income, Total	(9,453)	(270)	(2,560)
Amounts reclassified from accumulated other comprehensive income, Total	1,221	1,729	(501)
Total other comprehensive income	(8,232)	1,459	(3,061)
Ending Balance, Total	$ (18,957)	$ (10,725)	$ (12,184)

XML

Summary Of Accounting Policies

12 Months Ended

Dec. 31, 2014

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.

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.

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

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

Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based 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. The valuation allowances are reviewed at least annually.

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.

XML

Accounting For Suspended Exploratory Well Costs (Schedule Of Period End Capitalized Suspended Exploratory Well Costs) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized for a period of one year or less	$ 1,095	$ 293	$ 866
Capitalized suspended exploratory well costs, total	3,587	2,707	2,679	2,881
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 suspended exploratory well costs	1,659	1,705	1,176
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 suspended exploratory well costs	544	470	401
Capitalized For A Period Of Greater Than Ten Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs	289	239	236
Capitalized For A Period Greater Than One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized suspended exploratory well costs	$ 2,492	$ 2,414	$ 1,813

XML

Disclosures About Segments And Related Information (Tables)

12 Months Ended

Dec. 31, 2014

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, 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
As of December 31, 2012
Earnings after income tax		3,925		25,970		3,575		9,615		2,220		1,678		(2,103)		44,880
Earnings of equity companies included above		1,759		11,900		6		387		183		1,267		(492)		15,010
Sales and other operating revenue (1)		11,039		27,673		125,088		248,959		14,723		24,003		24		451,509
Intersegment revenue		8,764		47,507		20,963		62,130		12,409		9,750		258		-
Depreciation and depletion expense		5,104		7,340		594		1,280		376		508		686		15,888
Interest revenue		-		-		-		-		-		-		117		117
Interest expense		37		13		3		36		-		(1)		239		327
Income taxes		2,025		25,362		1,811		1,892		755		232		(1,032)		31,045
Additions to property, plant and equipment		9,697		21,769		480		1,153		338		659		1,083		35,179
Investments in equity companies		4,020		9,147		195		2,069		233		3,143		(277)		18,530
Total assets		86,146		140,848		18,451		40,956		7,238		18,886		21,270		333,795

(1) Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

Geographic Sales And Other Operating Revenue

Geographic
Sales and other operating revenue (1)		2014	2013	2012
		(millions of dollars)
United States		148,713	152,820	150,865
Non-U.S.		245,392	268,016	300,644
	Total	394,105	420,836	451,509
Significant non-U.S. revenue sources include:
	Canada	36,072	35,924	34,325
	United Kingdom	31,346	34,061	33,600
	Belgium	20,953	20,973	23,567
	Italy	18,880	19,273	18,228
	France	17,639	18,444	19,601
	Singapore	15,407	15,623	14,606
	Germany	14,816	15,701	15,871

(1) Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

Schedule Of Long-Lived Assets By Geographic Regions

Long-lived assets		2014	2013	2012
		(millions of dollars)
United States		104,000	98,271	94,336
Non-U.S.		148,668	145,379	132,613
	Total	252,668	243,650	226,949
Significant non-U.S. long-lived assets include:
	Canada	43,858	41,522	31,979
	Australia	15,328	14,258	13,415
	Nigeria	12,265	12,343	12,216
	Singapore	9,620	9,570	9,700
	Kazakhstan	9,138	8,530	7,785
	Angola	9,057	8,262	8,238
	Papua New Guinea	6,099	5,768	4,599
	Norway	5,139	6,542	7,040

XML

Miscellaneous Financial Information (Tables)

12 Months Ended

Dec. 31, 2014

Miscellaneous Financial Information [Abstract]

Crude Oil, Products And Merchandise

		2014	2013
		(billions of dollars)
Petroleum products		4.1	3.9
Crude oil		4.6	4.7
Chemical products		2.9	2.9
Gas/other		0.8	0.6
	Total	12.4	12.1

XML

Summary Of Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2014

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.

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.

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

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

Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based 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. The valuation allowances are reviewed at least annually.

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.

XML

Income, Sales-Based And Other Taxes (Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income, Sales-Based And Other Taxes [Abstract]
Balance at January 1	$ 7,838	$ 7,663	$ 4,922
Additions based on current year's tax positions	1,454	1,460	1,662
Additions for prior years' tax positions	448	464	2,559
Reductions for prior years' tax positions	(532)	(249)	(535)
Reductions due to lapse of the statute of limitations	(117)	(588)	(79)
Settlements with tax authorities	(43)	(849)	(855)
Foreign exchange effects / other	(62)	(63)	(11)
Balance at December 31	$ 8,986	$ 7,838	$ 7,663

XML

Investments, Advances And Long-Term Receivables (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Investments, Advances And Long-Term Receivables [Abstract]
Investments (Companies carried at equity in underlying assets)	$ 20,017	$ 19,619	$ 18,530
Advances (Companies carried at equity in underlying assets)	9,818	10,476
Total equity company investments and advances	29,835	30,095
Companies carried at cost or less and stock investments carried at fair value	526	115
Long-term receivables and miscellaneous investments at cost or less, net of reserves of $2,662 million and $2,938 million	4,878	6,118
Total	35,239	36,328
Reserves for long-term receivables and miscellaneous investments	$ 2,662	$ 2,938

XML

Income, Sales-Based And Other Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income, Sales-Based And Other Taxes [Abstract]

Schedule Of Income, Sales-Based And Other Taxes

						2014				2013				2012
				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		1,456		14,755	16,211	1,073		22,115	23,188	1,791		25,650	27,441
		Deferred - net		900		1,398	2,298	(116)		757	641	1,097		1,816	2,913
	U.S. tax on non-U.S. operations			5		-	5	37		-	37	89		-	89
			Total federal and non-U.S.	2,361		16,153	18,514	994		22,872	23,866	2,977		27,466	30,443
	State (1)			(499)		-	(499)	397		-	397	602		-	602
			Total income tax expense	1,862		16,153	18,015	1,391		22,872	24,263	3,579		27,466	31,045
Sales-based taxes				6,310		23,032	29,342	5,992		24,597	30,589	5,785		26,624	32,409
All other taxes and duties
	Other taxes and duties			378		31,908	32,286	955		32,275	33,230	1,406		34,152	35,558
	Included in production and
		manufacturing expenses		1,454		1,179	2,633	1,318		1,182	2,500	1,242		1,308	2,550
	Included in SG&A expenses			155		441	596	150		516	666	154		595	749
		Total other taxes and duties		1,987		33,528	35,515	2,423		33,973	36,396	2,802		36,055	38,857
			Total	10,159		72,713	82,872	9,806		81,442	91,248	12,166		90,145	102,311

(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

			2014	2013	2012
			(millions of dollars)
Income before income taxes
	United States		9,080	9,746	11,222
	Non-U.S.		42,550	47,965	67,504
		Total	51,630	57,711	78,726
Theoretical tax			18,071	20,199	27,554
Effect of equity method of accounting			(4,663)	(4,874)	(5,254)
Non-U.S. taxes in excess of theoretical U.S. tax			5,442	10,528	8,434
U.S. tax on non-U.S. operations			5	37	89
State taxes, net of federal tax benefit			(324)	258	391
Other			(516)	(1,885)	(169)
		Total income tax expense	18,015	24,263	31,045
Effective tax rate calculation
Income taxes			18,015	24,263	31,045
ExxonMobil share of equity company income taxes			5,678	6,061	5,859
		Total income taxes	23,693	30,324	36,904
Net income including noncontrolling interests			33,615	33,448	47,681
		Total income before taxes	57,308	63,772	84,585
Effective income tax rate			41%	48%	44%

Deferred Tax Liabilities/(Assets)

Tax effects of temporary differences for:		2014	2013
		(millions of dollars)
Property, plant and equipment		51,643	50,884
Other liabilities		4,359	3,474
	Total deferred tax liabilities	56,002	54,358
Pension and other postretirement benefits		(8,140)	(6,573)
Asset retirement obligations		(6,162)	(6,083)
Tax loss carryforwards		(4,099)	(3,393)
Other assets		(6,446)	(6,246)
	Total deferred tax assets	(24,847)	(22,295)
Asset valuation allowances		2,570	2,491
	Net deferred tax liabilities	33,725	34,554

Deferred Income Tax (Assets) And Liabilities By Balance Sheet Classification

Balance sheet classification		2014	2013
		(millions of dollars)
Other current assets		(2,001)	(3,575)
Other assets, including intangibles, net		(3,955)	(2,822)
Accounts payable and accrued liabilities		451	421
Deferred income tax liabilities		39,230	40,530
	Net deferred tax liabilities	33,725	34,554

Unrecognized Tax Benefits

Gross unrecognized tax benefits		2014	2013	2012
		(millions of dollars)
Balance at January 1		7,838	7,663	4,922
	Additions based on current year's tax positions	1,454	1,460	1,662
	Additions for prior years' tax positions	448	464	2,559
	Reductions for prior years' tax positions	(532)	(249)	(535)
	Reductions due to lapse of the statute of limitations	(117)	(588)	(79)
	Settlements with tax authorities	(43)	(849)	(855)
	Foreign exchange effects/other	(62)	(63)	(11)
Balance at December 31		8,986	7,838	7,663

Remaining Tax Years Subject To Examination By Major Tax Jurisdiction

Country of Operation	Open Tax Years
Abu Dhabi	2012 - 2014
Angola	2009 - 2014
Australia:	2000 - 2003
	2005
	2008 - 2014
Canada	2007 - 2014
Equatorial Guinea	2007 - 2014
Malaysia	2008 - 2014
Nigeria	2004 - 2014
Norway	2005 - 2014
Qatar	2008 - 2014
Russia	2011 - 2014
United Kingdom	2010 - 2014
United States	2006 - 2014

XML

Other Comprehensive Income Information (Tables)

12 Months Ended

Dec. 31, 2014

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, 2011		4,168	(13,291)	-	(9,123)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	842	(3,402)	-	(2,560)
Amounts reclassified from accumulated other
	comprehensive income	(2,600)	2,099	-	(501)
Total change in accumulated other comprehensive income		(1,758)	(1,303)	-	(3,061)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
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)

Reclassification Out Of Accumulated Other Comprehensive Income

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2014	2013	2012
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	(152)	23	4,352
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(1,571)	(2,616)	(3,621)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(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		2014	2013	2012
		(millions of dollars)
Foreign exchange translation adjustment		292	218	(236)
Postretirement benefits reserves adjustment (excluding amortization)		2,009	(1,540)	1,619
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(460)	(796)	(1,226)
Unrealized change in fair value of stock investments		34	-	-
Realized change in fair value of stock investments included in net income		(2)	-	-
Total		1,873	(2,118)	157

XML

Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2014

Cash Flow Information [Abstract]

Cash payments for interest and income taxes

	2014	2013	2012
	(millions of dollars)
Cash payments for interest	380	426	555
Cash payments for income taxes	18,085	25,066	24,349

XML

Consolidated Statement Of Changes In Equity (USD $) In Millions, except Share data	Total USD ($)	ExxonMobil Share Of Common Stock [Member] USD ($)	ExxonMobil Share Of Earnings Reinvested [Member] USD ($)	ExxonMobil Share Of Accumulated Other Comprehensive Income [Member] USD ($)	ExxonMobil Share Of Common Stock Held In Treasury [Member] USD ($)	ExxonMobil Share Of Equity [Member] USD ($)	Noncontrolling Interests [Member] USD ($)	Common Stock Outstanding [Member]
Balance at Dec. 31, 2011	$ 160,744	$ 9,512	$ 330,939	$ (9,123)	$ (176,932)	$ 154,396	$ 6,348
Balance (in shares) - outstanding at Dec. 31, 2011								4,734,000,000
Balance (in shares) - in treasury at Dec. 31, 2011					(3,285,000,000)
Balance (in shares) - issued at Dec. 31, 2011		8,019,000,000
Amortization of stock-based awards	806	806				806
Tax benefits related to stock-based awards	178	178				178
Other	(2,284)	(843)				(843)	(1,441)
Net income for the year	47,681		44,880			44,880	2,801
Dividends - common shares (company)			(10,092)			(10,092)
Dividends - common shares (NCI)							(327)
Dividends - common shares (total)	(10,419)
Other comprehensive income	(4,611)			(3,061)		(3,061)	(1,550)
Acquisitions, at cost (company)					(21,068)	(21,068)
Acquisitions, at cost (NCI)							(34)
Acquisitions, at cost (total)	(21,102)
Dispositions	667				667	667
Acquisitions (in shares)					(244,000,000)			(244,000,000)
Dispositions (in shares)					12,000,000			12,000,000
Balance at Dec. 31, 2012	171,660	9,653	365,727	(12,184)	(197,333)	165,863	5,797
Balance (in shares) - outstanding at Dec. 31, 2012								4,502,000,000
Balance (in shares) - in treasury at Dec. 31, 2012					(3,517,000,000)
Balance (in shares) - issued at Dec. 31, 2012		8,019,000,000
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)					(177,000,000)			(177,000,000)
Dispositions (in shares)					10,000,000			10,000,000
Balance at Dec. 31, 2013	180,495	10,077	387,432	(10,725)	(212,781)	174,003	6,492
Balance (in shares) - outstanding at Dec. 31, 2013								4,335,000,000
Balance (in shares) - in treasury at Dec. 31, 2013	3,684,000,000				(3,684,000,000)
Balance (in shares) - issued at Dec. 31, 2013	8,019,000,000	8,019,000,000
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)					(136,000,000)			(136,000,000)
Dispositions (in shares)					2,000,000			2,000,000
Balance at Dec. 31, 2014	$ 181,064	$ 10,792	$ 408,384	$ (18,957)	$ (225,820)	$ 174,399	$ 6,665
Balance (in shares) - outstanding at Dec. 31, 2014								4,201,000,000
Balance (in shares) - in treasury at Dec. 31, 2014	3,818,000,000				(3,818,000,000)
Balance (in shares) - issued at Dec. 31, 2014	8,019,000,000	8,019,000,000

XML

Additional Working Capital Information (Tables)

12 Months Ended

Dec. 31, 2014

Additional Working Capital Information [Abstract]

Schedule Of Notes, Accounts Receivable And Payable, Loans Payable, And Accrued Liabilities

			Dec. 31	Dec. 31
			2014	2013
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $113 million and $112 million		18,541	25,993
	Other, less reserves of $48 million and $28 million		9,468	7,159
		Total	28,009	33,152
Notes and loans payable
	Bank loans		473	723
	Commercial paper		16,225	14,051
	Long-term debt due within one year		770	1,034
		Total	17,468	15,808
Accounts payable and accrued liabilities
	Trade payables		25,286	30,920
	Payables to equity companies		6,589	6,587
	Accrued taxes other than income taxes		3,290	3,883
	Other		7,062	6,695
		Total	42,227	48,085

XML

Pension And Other Postretirement Benefits (Long-Term Rates Of Pension And Other Postretirement Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total recorded in other comprehensive income	$ 4,619	$ (7,281)	$ 1,523
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	4.00%	5.00%
Long-term rate of return on funded assets	7.25%	7.25%	7.25%
Long-term rate of compensation increase	5.75%	5.75%	5.75%
Service cost	677	801	665
Interest cost	807	749	820
Expected return on plan assets	(799)	(835)	(789)
Amortization of actuarial loss/(gain)	409	646	576
Amortization of prior service cost	8	7	7
Net pension enhancement and curtailment/settlement cost	276	723	333
Net periodic benefit cost	1,378	2,091	1,612
Net actuarial loss/(gain)	2,494	(1,302)	1,885
Amortization of actuarial (loss)/gain	(685)	(1,369)	(909)
Prior service cost/(credit)	(25)
Amortization of prior service (cost)/credit	(8)	(7)	(7)
Total recorded in other comprehensive income	1,776	(2,678)	969
Total recorded in net periodic benefit cost and other comprehensive income, before tax	3,154	(587)	2,581
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.30%	3.80%	4.00%
Long-term rate of return on funded assets	6.30%	6.40%	6.60%
Long-term rate of compensation increase	5.40%	5.50%	5.40%
Service cost	590	697	648
Interest cost	1,138	1,076	1,145
Expected return on plan assets	(1,193)	(1,128)	(1,109)
Amortization of actuarial loss/(gain)	628	852	844
Amortization of prior service cost	120	117	117
Net pension enhancement and curtailment/settlement cost		22	1,540	[1]
Net periodic benefit cost	1,283	1,636	3,185
Net actuarial loss/(gain)	2,969	(1,938)	1,906
Amortization of actuarial (loss)/gain	(628)	(874)	(2,384)
Prior service cost/(credit)	(70)	30	71
Amortization of prior service (cost)/credit	(120)	(117)	(117)
Foreign exchange rate changes	(688)	(155)	271
Total recorded in other comprehensive income	1,463	(3,054)	(253)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	2,746	(1,418)	2,932
Pension Benefits - Non-U.S. [Member] | Japan Transaction Disposal Group [Member]
Defined Benefit Plan Disclosure [Line Items]
Net pension enhancement and curtailment/settlement cost		1,420
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	5.00%	4.00%	5.00%
Long-term rate of return on funded assets	7.25%	7.25%	7.25%
Long-term rate of compensation increase	5.75%	5.75%	5.75%
Service cost	140	176	134
Interest cost	383	352	380
Expected return on plan assets	(37)	(41)	(38)
Amortization of actuarial loss/(gain)	116	228	170
Amortization of prior service cost	14	21	34
Net periodic benefit cost	616	736	680
Net actuarial loss/(gain)	1,518	(1,290)	1,008
Amortization of actuarial (loss)/gain	(116)	(228)	(170)
Amortization of prior service (cost)/credit	(14)	(21)	(34)
Foreign exchange rate changes	(8)	(10)	3
Total recorded in other comprehensive income	1,380	(1,549)	807
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$ 1,996	$ (813)	$ 1,487

[1] Non-U.S. net pension enhancement and curtailment/settlement cost for 2012 includes $1,420 million (on a consolidated-company, before-tax basis) of accumulated other comprehensive income for the postretirement benefit reserves adjustment that was recycled into earnings and included in the Japan restructuring gain reported in “Other income”.

XML

Incentive Program (Tables)

12 Months Ended

Dec. 31, 2014

Incentive Program [Abstract]

Summary Of Restricted Stock And Units Outstanding

	2014
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	45,207		78.29
2013 award issued in 2014	9,705		94.47
Vested	(10,286)		79.89
Forfeited	(187)		78.89
Issued and outstanding at December 31	44,439		81.45

Grant Value Of Restricted Stock And Units

Value of restricted stock and units	2014	2013	2012
Grant price (dollars)	95.20	94.47	87.24
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	858	843	797
Units settled in cash	73	76	77
Total value	931	919	874

XML

Equity Company Information (Narrative) (Details) (USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Share of equity company sales revenues from sales to consolidated companies	14.00%	13.00%	16.00%
Rosneft VIE Joint Venture [Member]
Schedule of Equity Method Investments [Line Items]
Maximum Exposure to Loss from Rosneft JV's	1

XML

Incentive Program (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	108,000,000
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 0 months 0 days
Restricted Stock [Member]
Long-term incentive awards	9,775,000	9,729,000	10,017,000
Unrecognized compensation cost	$ 2,339
Unrecognized compensation cost, weighted-average period of recognition, years	4 years 6 months 0 days
Compensation cost charged against income	831	854	854
Income tax benefit recognized in income	76	78	79
Fair value of shares/awards vested	946	1,040	926
Cash payments, vested restricted stock units	$ 73	$ 67	$ 66
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 0 months 0 days
Restricted Stock [Member] | Minimum [Member] | Executive Officer [Member]
Vesting Period	5 years 0 months 0 days
Restricted Stock [Member] | Maximum [Member]
Vesting Period	7 years 0 months 0 days
Restricted Stock [Member] | Maximum [Member] | Executive Officer [Member]
Vesting Period	10 years 0 months 0 days

XML

Consolidated Statement Of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues and other income
Sales and other operating revenue	$ 394,105	[1],[2]	$ 420,836	[1],[2]	$ 451,509	[1],[2]
Income from equity affiliates	13,323		13,927		15,010
Other income	4,511		3,492		14,162
Total revenues and other income	411,939		438,255		480,681
Costs and other deductions
Crude oil and product purchases	225,972		244,156		263,535
Production and manufacturing expenses	40,859		40,525		38,521
Selling, general and administrative expenses	12,598		12,877		13,877
Depreciation and depletion	17,297		17,182		15,888
Exploration expenses, including dry holes	1,669		1,976		1,840
Interest expense	286		9		327
Sales-based taxes	29,342	[1]	30,589	[1]	32,409	[1]
Other taxes and duties	32,286		33,230		35,558
Total costs and other deductions	360,309		380,544		401,955
Income before income taxes	51,630		57,711		78,726
Income taxes	18,015		24,263		31,045
Net income including noncontrolling interests	33,615		33,448		47,681
Net income attributable to noncontrolling interests	1,095		868		2,801
Net income attributable to ExxonMobil	$ 32,520		$ 32,580		$ 44,880
Earnings per common share (dollars)	$ 7.6	[3]	$ 7.37	[3]	$ 9.7	[3]
Earnings per common share - assuming dilution (dollars)	$ 7.6		$ 7.37		$ 9.7

[1] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012.

[2] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. 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

Miscellaneous Financial Information (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Miscellaneous Financial Information [Abstract]
Research and development expense	$ 971,000,000	$ 1,044,000,000	$ 1,042,000,000
Foreign currency transaction gain/(loss), before tax	(225,000,000)	155,000,000	159,000,000
Gains on combined effects of LIFO inventory accumulations and draw-downs	187,000,000	282,000,000	328,000,000
Replacement cost of inventories estimated to exceed LIFO carrying values	$ 10,600,000,000	$ 21,200,000,000

XML

Income, Sales-Based And Other Taxes (Schedule Of Income, Sales-Based And Other Taxes) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Income, Sales-Based and Other Taxes [Line Items]
Current	$ 16,211		$ 23,188		$ 27,441
Deferred - net	2,298		641		2,913
U.S. tax on non-U.S. operations	5		37		89
Total federal and non-U.S.	18,514		23,866		30,443
State	(499)	[1]	397		602
Total income tax expense	18,015		24,263		31,045
Sales-based taxes	29,342	[2]	30,589	[2]	32,409	[2]
Other taxes and duties	32,286		33,230		35,558
Other taxes and duties included in production and manufacturing expenses	2,633		2,500		2,550
Other taxes and duties included in SG&A expenses	596		666		749
Total other taxes and duties	35,515		36,396		38,857
Total	82,872		91,248		102,311
U.S. [Member]
Income, Sales-Based and Other Taxes [Line Items]
Current	1,456		1,073		1,791
Deferred - net	900		(116)		1,097
U.S. tax on non-U.S. operations	5		37		89
Total federal and non-U.S.	2,361		994		2,977
State	(499)	[1]	397		602
Total income tax expense	1,862		1,391		3,579
Sales-based taxes	6,310		5,992		5,785
Other taxes and duties	378		955		1,406
Other taxes and duties included in production and manufacturing expenses	1,454		1,318		1,242
Other taxes and duties included in SG&A expenses	155		150		154
Total other taxes and duties	1,987		2,423		2,802
Total	10,159		9,806		12,166
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	14,755		22,115		25,650
Deferred - net	1,398		757		1,816
Total federal and non-U.S.	16,153		22,872		27,466
Total income tax expense	16,153		22,872		27,466
Sales-based taxes	23,032		24,597		26,624
Other taxes and duties	31,908		32,275		34,152
Other taxes and duties included in production and manufacturing expenses	1,179		1,182		1,308
Other taxes and duties included in SG&A expenses	441		516		595
Total other taxes and duties	33,528		33,973		36,055
Total	$ 72,713		$ 81,442		$ 90,145

[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 $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012.

XML

Consolidated Balance Sheet (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Consolidated Balance Sheet [Abstract]
Common stock, without par value
Common stock, shares authorized	9,000,000,000	9,000,000,000
Common stock, shares issued	8,019,000,000	8,019,000,000
Common stock held in treasury, shares	3,818,000,000	3,684,000,000

XML

Disclosures About Segments And Related Information (Schedule Of Long-Lived Assets By Geographic Regions) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long-lived assets	$ 252,668	$ 243,650	$ 226,949
U.S. [Member]
Long-lived assets	104,000	98,271	94,336
Non-U.S. [Member]
Long-lived assets	148,668	145,379	132,613
Canada [Member]
Long-lived assets	43,858	41,522	31,979
Australia [Member]
Long-lived assets	15,328	14,258	13,415
Nigeria [Member]
Long-lived assets	12,265	12,343	12,216
Singapore [Member]
Long-lived assets	9,620	9,570	9,700
Kazakhstan [Member]
Long-lived assets	9,138	8,530	7,785
Angola [Member]
Long-lived assets	9,057	8,262	8,238
Papua New Guinea [Member]
Long-lived assets	6,099	5,768	4,599
Norway [Member]
Long-lived assets	$ 5,139	$ 6,542	$ 7,040

XML

Property, Plant And Equipment And Asset Retirement Obligations (Asset Retirement Obligations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant And Equipment And Asset Retirement Obligations [Abstract]
Beginning balance	$ 12,988	$ 11,973
Accretion expense and other provisions	871	785
Reduction due to property sales	(151)	(97)
Payments made	(724)	(664)
Liabilities incurred	122	603
Foreign currency translation	(908)	(344)
Revisions	1,226	732
Ending balance	$ 13,424	$ 12,988

XML

Income, Sales-Based And Other Taxes (Deferred Income Tax (Assets) And Liabilities By Balance Sheet Classification) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income, Sales-Based And Other Taxes [Abstract]
Other current assets	$ (2,001)	$ (3,575)
Other assets, including intangibles, net	(3,955)	(2,822)
Accounts payable and accrued liabilities	451	421
Deferred income tax liabilities	39,230	40,530
Net deferred tax liabilities	$ 33,725	$ 34,554

XML

Property, Plant And Equipment And Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant And Equipment And Asset Retirement Obligations [Abstract]

Property, Plant And Equipment

		December 31, 2014		December 31, 2013
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,170	205,308	336,359	197,554
Downstream		53,327	22,639	54,456	23,219
Chemical		30,717	14,918	29,487	13,965
Other		15,575	9,803	14,215	8,912
	Total	446,789	252,668	434,517	243,650

Asset Retirement Obligations

		2014	2013
		(millions of dollars)
Beginning balance		12,988	11,973
	Accretion expense and other provisions	871	785
	Reduction due to property sales	(151)	(97)
	Payments made	(724)	(664)
	Liabilities incurred	122	603
	Foreign currency translation	(908)	(344)
	Revisions	1,226	732
Ending balance		13,424	12,988

XML

Leased Facilities (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Leased Facilities [Abstract]
Minimum undiscounted lease commitments	$ 6,213
Estimated related rental income from noncancelable subleases	$ 70

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2014

Long-Term Debt [Abstract]

Long-Term Debt

14. Long-Term Debt

At December 31, 2014, long-term debt consisted of $11,341 million due in U.S. dollars and $312 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 $770 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 $5,500 million of long-term debt in the first quarter of 2014.The amounts of long-term debt maturing in each of the four years after December 31, 2015, in millions of dollars, are: 2016 – $537; 2017 – $2,993; 2018 –$872; and 2019 –$2,353. At December 31, 2014, the Corporation’s unused long-term credit lines were $0.5 billion.

Summarized long-term debt at year-end 2014 and 2013 are shown in the table below:

			2014	2013
			(millions of dollars)
Exxon Mobil Corporation
	0.921% notes due 2017		1,500	-
	Floating-rate notes due 2017 (1)		750	-
	1.819% notes due 2019		1,750	-
	Floating-rate notes due 2019 (2)		500	-
	3.176% notes due 2024		1,000	-
XTO Energy Inc. (3)
	5.000% senior notes due 2015		-	132
	5.300% senior notes due 2015		-	243
	5.650% senior notes due 2016		207	212
	6.250% senior notes due 2017		477	489
	5.500% senior notes due 2018		383	389
	6.500% senior notes due 2018		474	485
	6.100% senior notes due 2036		199	200
	6.750% senior notes due 2037		309	312
	6.375% senior notes due 2038		236	238
Mobil Producing Nigeria Unlimited (4)
	Variable notes due 2015-2019		399	742
Esso (Thailand) Public Company Ltd.(5)
	Variable notes due 2015-2019		121	177
Mobil Corporation
	8.625% debentures due 2021		249	249
Industrial revenue bonds due 2015-2051 (6)			2,611	2,527
Other U.S. dollar obligations (7)			104	112
Other foreign currency obligations			9	9
Capitalized lease obligations(8)			375	375
		Total long-term debt	11,653	6,891

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

(2)Average effective interest rate of 0.4% in 2014.

(3)Includes premiums of $219 millionin 2014 and $271 million in 2013.

(4)Average effective interest rate of 4.5% in 2014 and 4.6% in 2013.

(5)Average effective interest rate of 2.4% in 2014 and 3.3% in 2013.

(6)Average effective interest rate of 0.03% in 2014 and 0.06% in 2013.

(7)Average effective interest rate of 4.2% in 2014 and 4.4% in 2013.

(8)Average imputed interest rate of 7.0% in 2014 and 7.8% in 2013.

XML

Accounting For Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2014

Accounting For Suspended Exploratory Well Costs [Abstract]

Change In Capitalized Suspended Exploratory Well Costs

			2014	2013	2012
			(millions of dollars)
Balance beginning at January 1			2,707	2,679	2,881
	Additions pending the determination of proved reserves		1,095	293	868
	Charged to expense		(28)	(52)	(95)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(160)	(107)	(631)
	Divestments/Other		(27)	(106)	(344)
Ending balance at December 31			3,587	2,707	2,679
Ending balance attributed to equity companies included above			645	13	3

Period End Capitalized Suspended Exploratory Well Costs

			2014	2013	2012
			(millions of dollars)
Capitalized for a period of one year or less			1,095	293	866
	Capitalized for a period of between one and five years		1,659	1,705	1,176
	Capitalized for a period of between five and ten years		544	470	401
	Capitalized for a period of greater than ten years		289	239	236
Capitalized for a period greater than one year - subtotal			2,492	2,414	1,813
		Total	3,587	2,707	2,679

Number Of Projects With Suspended Exploratory Well Costs

			2014	2013	2012
Number of projects with first capitalized well drilled in the preceding 12 months			8	8	10
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		53	50	45
		Total	61	58	55

Additional Detail For The 38 Projects With Completed Exploratory Activity Progressing Toward Development

			Years
		Dec. 31,	Wells
Country/Project		2014	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		8	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		12	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		38	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		28	2008 - 2011	Development activity under way, while continuing commercial discussions with the
				government.
- Kedung Keris		11	2011	Evaluating development plan to tie into planned production facilities.
- Natuna		118	1981 - 1983	Development activity under way, while continuing discussions with the government
				on contract terms pursuant to executed Heads of Agreement.
Kazakhstan
- Kairan		53	2004 - 2007	Evaluating commercialization and field development alternatives, while continuing
				discussions with the government regarding the development plan.
Malaysia
- Besar		18	1992 - 2010	Gas field off the east coast of Malaysia; progressing development plan.
- Bindu		2	1995	Awaiting capacity in existing/planned infrastructure.
Nigeria
- Bolia		15	2002 - 2006	Evaluating development plan, while continuing discussions with the government
				regarding regional hub strategy.
- Bosi		79	2002 - 2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Bosi Central		16	2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Owowo		50	2009 - 2012	Continuing discussions with the government regarding contract terms.
- 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		15	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		18	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		29	2008 - 2013	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.
- P'nyang		58	2012	Evaluating development alternatives to tie into existing/planned infrastructure.
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 2014 (38 projects)		1,035

XML

Income, Sales-Based And Other Taxes (Deferred Income Taxes Assets And Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Income, Sales-Based And Other Taxes [Abstract]
Property, plant and equipment	$ 51,643	$ 50,884
Other liabilities	4,359	3,474
Total deferred tax liabilities	56,002	54,358
Pension and other postretirement benefits	(8,140)	(6,573)
Asset retirement obligations	(6,162)	(6,083)
Tax loss carryforwards	(4,099)	(3,393)
Other assets	(6,446)	(6,246)
Total deferred tax assets	(24,847)	(22,295)
Asset valuation allowances	2,570	2,491
Net deferred tax liabilities	$ 33,725	$ 34,554

XML

Litigation And Other Contingencies

12 Months Ended

Dec. 31, 2014

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 December31,2014, 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, 2014
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			3,506		41	3,547
	Other			2,920		3,982	6,902
		Total		6,426		4,023	10,449
(1) ExxonMobil share.

The debt-related guarantees shown above include a $3.4 billion completion guarantee provided to lenders in support of the project financing for the Papua New Guinea Liquefied Natural Gas project. On February 4, 2015, the obligations under this guarantee were terminated per the terms of the loan agreement.

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
		2016-	2020 and
	2015	2019	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	150	608		337	1,095

(1) Undiscounted obligations of $1,095million mainly pertain to pipeline throughput agreements and include $433million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $168million, totaled $927million.

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) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. 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 (ICC).Following the favorable ICSID decision in the fourth quarter of 2014, ExxonMobil recognized earnings of $269 million, net of the remaining asset value, for the proceeds received from the earlier ICC award.

Judgment was entered on the ICSID award by the United States District Court for the Southern District of New York on October 10, 2014. A motion to vacate that judgment on procedural grounds was filed by the Republic of Venezuela on October 14, 2014, which was denied by the court. Thereafter, the Republic of Venezuela filed a motion 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.

On October 23, 2014, the Republic of Venezuela filed with ICSID an application to revise the ICSID award such that it requires repayment of the value of the ICC award to PdVSA at the same time as payment is made to the ExxonMobil affiliates for the ICSID award and that provision be made for interest on the amount to be repaid. Thereafter, pursuant to ICSID arbitration rules, the ICSID award was stayed pending further action of the Tribunal. On October 27, 2014, ExxonMobil filed a response with ICSID that contests the application for revision of that award on both factual and jurisdictional grounds. On February 2, 2015, the Republic of Venezuela filed an application to annul the ICSID award. The 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.Upon registration of the application with ICSID on February 9, 2015, a further stay of the ICSID award was entered.

The federal court in New York has stayed its judgment until such time as the stays of the ICSID award entered following the Government of Venezuela’s filing of its two applications have 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 have appealed that judgment. 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. 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.

XML

Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings per common share
Net income attributable to ExxonMobil	$ 32,520		$ 32,580		$ 44,880
Weighted average number of common shares outstanding	4,282		4,419		4,628
Earnings per common share (dollars)	$ 7.6	[1]	$ 7.37	[1]	$ 9.7	[1]
Dividends paid per common share (dollars)	$ 2.7		$ 2.46		$ 2.18

[1] The earnings per common share and earnings per common share - assuming dilution are the same in each period shown.

XML

Consolidated Statement Of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income including noncontrolling interests	$ 33,615	$ 33,448	$ 47,681
Adjustments for noncash transactions
Depreciation and depletion	17,297	17,182	15,888
Deferred income tax charges/(credits)	1,540	754	3,142
Postretirement benefits expense in excess of/(less than) net payments	524	2,291	(315)
Other long-term obligation provisions in excess of/(less than) payments	1,404	(2,566)	1,643
Dividends received greater than/(less than) equity in current earnings of equity companies	(358)	3	(1,157)
Changes in operational working capital, excluding cash and debt
Reduction/(increase) - Notes and accounts receivable	3,118	(305)	(1,082)
Reduction/(increase) - Inventories	(1,343)	(1,812)	(1,873)
Reduction/(increase) - Other current assets	(68)	(105)	(42)
Increase/(reduction) - Accounts and other payables	(6,639)	(2,498)	3,624
Net (gain) on asset sales	(3,151)	(1,828)	(13,018)
All other items - net	(823)	350	1,679
Net cash provided by operating activities	45,116	44,914	56,170
Cash flows from investing activities
Additions to property, plant and equipment	(32,952)	(33,669)	(34,271)
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments	4,035	2,707	7,655
Decrease/(increase) in restricted cash and cash equivalents	227	72	63
Additional investments and advances	(1,631)	(4,435)	(598)
Collection of advances	3,346	1,124	1,550
Net cash used in investing activities	(26,975)	(34,201)	(25,601)
Cash flows from financing activities
Additions to long-term debt	5,731	345	995
Reductions in long-term debt	(69)	(13)	(147)
Additions to short-term debt		16	958
Reductions in short-term debt	(745)	(756)	(4,488)
Additions/(reductions) in debt with three months or less maturity	2,049	12,012	(226)
Cash dividends to ExxonMobil shareholders	(11,568)	(10,875)	(10,092)
Cash dividends to noncontrolling interests	(248)	(304)	(327)
Changes in noncontrolling interests		(1)	204
Tax benefits related to stock-based awards	115	48	130
Common stock acquired	(13,183)	(15,998)	(21,068)
Common stock sold	30	50	193
Net cash used in financing activities	(17,888)	(15,476)	(33,868)
Effects of exchange rate changes on cash	(281)	(175)	217
Increase/(decrease) in cash and cash equivalents	(28)	(4,938)	(3,082)
Cash and cash equivalents at beginning of year	4,644	9,582	12,664
Cash and cash equivalents at end of year	$ 4,616	$ 4,644	$ 9,582

XML

Consolidated Statement Of Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Consolidated Statement Of Income [Abstract]
Sales-based taxes included in sales and other operating revenue	$ 29,342	[1]	$ 30,589	[1]	$ 32,409	[1]

[1] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012.

XML

Property, Plant And Equipment And Asset Retirement Obligations

12 Months Ended

Dec. 31, 2014

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, 2014		December 31, 2013
Property, Plant and Equipment		Cost	Net	Cost	Net
		(millions of dollars)
Upstream		347,170	205,308	336,359	197,554
Downstream		53,327	22,639	54,456	23,219
Chemical		30,717	14,918	29,487	13,965
Other		15,575	9,803	14,215	8,912
	Total	446,789	252,668	434,517	243,650

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.

Accumulated depreciation and depletion totaled $194,121 million at the end of 2014 and $190,867 million at the end of 2013. Interest capitalized in 2014, 2013 and 2012 was $344 million, $309 million and $506 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:

		2014	2013
		(millions of dollars)
Beginning balance		12,988	11,973
	Accretion expense and other provisions	871	785
	Reduction due to property sales	(151)	(97)
	Payments made	(724)	(664)
	Liabilities incurred	122	603
	Foreign currency translation	(908)	(344)
	Revisions	1,226	732
Ending balance		13,424	12,988

XML

Disclosures About Segments And Related Information (Schedule Of Geographic Sales And Other Operating Revenue) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	$ 394,105	[1]	$ 420,836	[1]	$ 451,509	[1]
Sales-based taxes	29,342	[2]	30,589	[2]	32,409	[2]
U.S. [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	148,713	[1]	152,820	[1]	150,865	[1]
Sales-based taxes	6,310		5,992		5,785
Non-U.S. [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	245,392	[1]	268,016	[1]	300,644	[1]
Sales-based taxes	23,032		24,597		26,624
Canada [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	36,072	[1]	35,924	[1]	34,325	[1]
United Kingdom [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	31,346	[1]	34,061	[1]	33,600	[1]
Belgium [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	20,953	[1]	20,973	[1]	23,567	[1]
Italy [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	18,880	[1]	19,273	[1]	18,228	[1]
France [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	17,639	[1]	18,444	[1]	19,601	[1]
Singapore [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	15,407	[1]	15,623	[1]	14,606	[1]
Germany [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Sales and other operating revenue	$ 14,816	[1]	$ 15,701	[1]	$ 15,871	[1]

[1] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

[2] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012.

XML

Disclosures About Segments And Related Information (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosures About Segments And Related Information [Abstract]
Non-debt-related interest expense	$ 129	$ (123)	$ 202

XML

Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
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		4,194,690,266
Entity Public Float			$ 429

XML

Accounting For Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2014

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:

			2014	2013	2012
			(millions of dollars)
Balance beginning at January 1			2,707	2,679	2,881
	Additions pending the determination of proved reserves		1,095	293	868
	Charged to expense		(28)	(52)	(95)
	Reclassifications to wells, facilities and equipment based on the
		determination of proved reserves	(160)	(107)	(631)
	Divestments/Other		(27)	(106)	(344)
Ending balance at December 31			3,587	2,707	2,679
Ending balance attributed to equity companies included above			645	13	3

Period end capitalized suspended exploratory well costs:

			2014	2013	2012
			(millions of dollars)
Capitalized for a period of one year or less			1,095	293	866
	Capitalized for a period of between one and five years		1,659	1,705	1,176
	Capitalized for a period of between five and ten years		544	470	401
	Capitalized for a period of greater than ten years		289	239	236
Capitalized for a period greater than one year - subtotal			2,492	2,414	1,813
		Total	3,587	2,707	2,679

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical 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.

			2014	2013	2012
Number of projects with first capitalized well drilled in the preceding 12 months			8	8	10
Number of projects that have exploratory well costs capitalized for a period
	of greater than 12 months		53	50	45
		Total	61	58	55

Of the 53 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2014, 15 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 38 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 38 projects, which total $1,035 million.

			Years
		Dec. 31,	Wells
Country/Project		2014	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		8	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
				infrastructure.
- SE Longtom		12	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
- SE Remora		38	2010	Gas field near Marlin development, awaiting capacity in existing/planned infrastructure.
Indonesia
- Alas Tua West		16	2010	Evaluating development plan to tie into planned production facilities.
- Cepu Gas		28	2008 - 2011	Development activity under way, while continuing commercial discussions with the
				government.
- Kedung Keris		11	2011	Evaluating development plan to tie into planned production facilities.
- Natuna		118	1981 - 1983	Development activity under way, while continuing discussions with the government
				on contract terms pursuant to executed Heads of Agreement.
Kazakhstan
- Kairan		53	2004 - 2007	Evaluating commercialization and field development alternatives, while continuing
				discussions with the government regarding the development plan.
Malaysia
- Besar		18	1992 - 2010	Gas field off the east coast of Malaysia; progressing development plan.
- Bindu		2	1995	Awaiting capacity in existing/planned infrastructure.
Nigeria
- Bolia		15	2002 - 2006	Evaluating development plan, while continuing discussions with the government
				regarding regional hub strategy.
- Bosi		79	2002 - 2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Bosi Central		16	2006	Development activity under way, while continuing discussions with the government
				regarding development plan.
- Erha Northeast		26	2008	Evaluating development plan for tieback to existing production facilities.
- Owowo		50	2009 - 2012	Continuing discussions with the government regarding contract terms.
- 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		15	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
- Lavrans		18	1995 - 1999	Evaluating development plan, awaiting capacity in existing Kristin production facility.
- Other (7 projects)		29	2008 - 2013	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.
- P'nyang		58	2012	Evaluating development alternatives to tie into existing/planned infrastructure.
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 2014 (38 projects)		1,035

XML

Pension And Other Postretirement Benefits (Change In Plan Assets Of Pension And Other Postretirement Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	$ 11,190		$ 12,632
Actual return on plan assets	1,497		617
Company contribution	1,476		101
Other			11
Fair value at December 31	12,915		11,190
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	19,283		18,090
Actual return on plan assets	3,153		1,604
Foreign exchange rate changes	(1,738)		(270)
Company contribution	554		919
Other	(245)		(191)
Fair value at December 31	20,095		19,283
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value at January 1	620		581
Actual return on plan assets	41		64
Company contribution	31		35
Fair value at December 31	468		620
Benefit Payments For Funded Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	(1,248)	[1]	(2,171)	[1]
Benefit Payments For Funded Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	(912)	[1]	(869)	[1]
Benefit Payments For Funded Plans [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits paid	$ (224)	[1]	$ (60)	[1]

[1] Benefit payments for funded plans.

XML

Pension And Other Postretirement Benefits (Expected Contribution Pension Benefits And Other Postretirement Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits payments expected in 2015	$ 1,628
Benefits payments expected in 2016	1,554
Benefits payments expected in 2017	1,529
Benefits payments expected in 2018	1,445
Benefits payments expected in 2019	1,410
Benefits payments expected in 2020-2024	6,714
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Contributions expected in 2015	560
Benefits payments expected in 2015	1,194
Benefits payments expected in 2016	1,213
Benefits payments expected in 2017	1,278
Benefits payments expected in 2018	1,298
Benefits payments expected in 2019	1,339
Benefits payments expected in 2020-2024	6,988
Gross Other Post Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits payments expected in 2015	467
Benefits payments expected in 2016	479
Benefits payments expected in 2017	490
Benefits payments expected in 2018	499
Benefits payments expected in 2019	507
Benefits payments expected in 2020-2024	2,613
Other Postretirement Benefits Medicare Subsidy Receipt [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits payments expected in 2015	24
Benefits payments expected in 2016	25
Benefits payments expected in 2017	26
Benefits payments expected in 2018	28
Benefits payments expected in 2019	29
Benefit payments expected in 2020-2024	$ 172

XML

Consolidated Statement Of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statement Of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 33,615	$ 33,448	$ 47,681
Other comprehensive income (net of income taxes)
Foreign exchange translation adjustment	(5,847)	(3,620)	920
Adjustment for foreign exchange translation (gain)/loss included in net income	152	(23)	(4,352)
Postretirement benefits reserves adjustment (excluding amortization)	(4,262)	3,174	(3,574)
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	1,111	1,820	2,395
Unrealized change in fair value of stock investments	(63)
Realized (gain)/ loss from stock investments included in net income	3
Total other comprehensive income	(8,906)	1,351	(4,611)
Comprehensive income including noncontrolling interests	24,709	34,799	43,070
Comprehensive income attributable to noncontrolling interests	421	760	1,251
Comprehensive income attributable to ExxonMobil	$ 24,288	$ 34,039	$ 41,819

XML

Other Comprehensive Income Information

12 Months Ended

Dec. 31, 2014

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, 2011		4,168	(13,291)	-	(9,123)
Current period change excluding amounts reclassified
	from accumulated other comprehensive income	842	(3,402)	-	(2,560)
Amounts reclassified from accumulated other
	comprehensive income	(2,600)	2,099	-	(501)
Total change in accumulated other comprehensive income		(1,758)	(1,303)	-	(3,061)
Balance as of December 31, 2012		2,410	(14,594)	-	(12,184)
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)

Amounts Reclassified Out of Accumulated Other
Comprehensive Income - Before-tax Income/(Expense)		2014	2013	2012
		(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
	(Statement of Income line: Other income)	(152)	23	4,352
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs (1)	(1,571)	(2,616)	(3,621)
Realized change in fair value of stock investments included in net income
	(Statement of Income line: Other income)	(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		2014	2013	2012
		(millions of dollars)
Foreign exchange translation adjustment		292	218	(236)
Postretirement benefits reserves adjustment (excluding amortization)		2,009	(1,540)	1,619
Amortization and settlement of postretirement benefits reserves
	adjustment included in net periodic benefit costs	(460)	(796)	(1,226)
Unrealized change in fair value of stock investments		34	-	-
Realized change in fair value of stock investments included in net income		(2)	-	-
Total		1,873	(2,118)	157

XML

Miscellaneous Financial Information

12 Months Ended

Dec. 31, 2014

Miscellaneous Financial Information [Abstract]

Miscellaneous Financial Information

3. Miscellaneous Financial Information

Research and development expenses totaled $971 million in 2014, $1,044 million in 2013 and $1,042 million in 2012.

Net income included before-tax aggregate foreign exchange transaction losses of $225million, and gains of $155 million and $159 million in 2014, 2013 and 2012, respectively.

In 2014, 2013 and 2012, net income included gains of $187 million, $282 million and $328 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 $10.6 billion and $21.2 billion at December 31, 2014, and 2013, respectively.

Crude oil, products and merchandise as of year-end 2014 and 2013 consist of the following:

		2014	2013
		(billions of dollars)
Petroleum products		4.1	3.9
Crude oil		4.6	4.7
Chemical products		2.9	2.9
Gas/other		0.8	0.6
	Total	12.4	12.1

XML

Incentive Program

12 Months Ended

Dec. 31, 2014

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 2014, remaining shares available for award under the 2003 Incentive Program were 108million.

Restricted Stock and Restricted Stock Units. Awards totaling 9,775 thousand, 9,729 thousand, and 10,017 thousandof restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2014, 2013 and 2012, 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, 2014.

	2014
		Weighted Average
		Grant-Date
Restricted stock and units outstanding	Shares	Fair Value per Share
	(thousands)	(dollars)
Issued and outstanding at January 1	45,207		78.29
2013 award issued in 2014	9,705		94.47
Vested	(10,286)		79.89
Forfeited	(187)		78.89
Issued and outstanding at December 31	44,439		81.45

Value of restricted stock and units	2014	2013	2012
Grant price (dollars)	95.20	94.47	87.24
Value at date of grant:	(millions of dollars)
Restricted stock and units settled in stock	858	843	797
Units settled in cash	73	76	77
Total value	931	919	874

As of December 31, 2014, there was $2,339 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 $831 million, $854 million and$854 million for 2014, 2013 and 2012, respectively. The income taxbenefit recognized in income related to this compensation expensewas $76 million, $78 million and $79 million for the same periods, respectively. The fair value of shares and units vested in 2014,2013 and 2012 was $946 million, $1,040 million and $926 million, respectively. Cash payments of $73 million, $67 million and $66 million for vested restricted stock units settled in cash were made in 2014, 2013 and 2012, respectively.

XML

Leased Facilities

12 Months Ended

Dec. 31, 2014

Leased Facilities [Abstract]

Leased Facilities

11. Leased Facilities

At December 31, 2014, 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 $6,213 million as indicated in the table. Estimated related rental income from noncancelable subleases is $70 million.

		Related
	Lease Payments	Sublease
	Under Minimum	Rental
	Commitments	Income
	(millions of dollars)
2015	2,034	31
2016	1,379	7
2017	774	6
2018	418	3
2019	312	3
2020 and beyond	1,296	20
Total	6,213	70

Net rental cost under both cancelable and noncancelable operating leases incurred during 2014, 2013 and 2012 were as follows:

	2014	2013	2012
	(millions of dollars)
Rental cost	4,077	3,841	3,851
Less sublease rental income	52	44	44
Net rental cost	4,025	3,797	3,807

XML

Pension And Other Postretirement Benefits (Summary Of The Change In Accumulated Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	$ (4,619)	$ 7,281	$ (1,523)
(Charge)/credit to income tax (see Note 4)	1,549	(2,336)	393
(Charge)/credit to investment in equity companies	(81)	49	(49)
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax	(3,151)	4,994	(1,179)
Charge/(credit) to equity of noncontrolling interests	85	(279)	(124)
(Charge)/credit to other comprehensive income attributable to ExxonMobil	(3,066)	4,715	(1,303)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	(1,776)	2,678	(969)
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	(1,463)	3,054	253
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total (charge)/credit to other comprehensive income, before tax	$ (1,380)	$ 1,549	$ (807)

XML

Equity Company Information

12 Months Ended

Dec. 31, 2014

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, natural gas marketing, and refining operations 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 14 percent, 13 percent and 16 percent in the years 2014, 2013 and 2012, 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. In compliance with the sanctions and all general and specific licenses, prohibited activities involving offshore Russia in the Black Sea, Arctic regions, and onshore western Siberia have been wound down. The Corporation's maximum exposure to loss from these joint ventures as of December 31, 2014, is $1.0 billion.

		2014			2013			2012
Equity Company			ExxonMobil			ExxonMobil			ExxonMobil
Financial Summary		Total		Share	Total		Share	Total		Share
		(millions of dollars)
Total revenues		183,708		55,855	236,161		68,084	224,953		67,572
Income before income taxes		65,549		19,014	69,454		19,999	69,411		20,882
Income taxes		20,520		5,684	21,618		6,069	20,703		5,868
	Income from equity affiliates	45,029		13,330	47,836		13,930	48,708		15,014
Current assets		49,905		16,802	62,398		19,545	59,612		18,483
Long-term assets		110,754		33,619	116,450		35,695	111,131		33,798
	Total assets	160,659		50,421	178,848		55,240	170,743		52,281
Current liabilities		37,333		11,472	54,550		15,243	49,698		14,265
Long-term liabilities		66,231		19,470	68,857		20,873	68,855		19,715
	Net assets	57,095		19,479	55,441		19,124	52,190		18,301

A list of significant equity companies as of December 31, 2014, 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
Chalmette Refining, LLC	50
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 USA L.P.	50
Saudi Yanbu Petrochemical Co.	50

XML

Accounting For Suspended Exploratory Well Costs (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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, 2014	53	50	45
Number of projects that have drilling in the preceding twelve months or exploratory activity planned in the next two years as of December 31, 2014	15
Number of projects with completed exploratory activity progressing toward development as of December 31, 2014	38
Capitalized exploratory well costs	$ 3,587	$ 2,707	$ 2,679	$ 2,881
Total 38 Projects [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	$ 1,035

XML

Cash Flow Information

12 Months Ended

Dec. 31, 2014

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 2014, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows 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. For 2012, the amount includes before-tax gains related to the Japan restructuring, the sale of an Upstream property in Angola, exchanges of Upstream properties, the sale of U.S. service stations and the sale of Downstream affiliates in Malaysia and Switzerland.These gains are reported in “Other income” on the Consolidated Statement of Income.

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.

In 2012, the Corporation’s interest in a cost company was redeemed. As part of the redemption, a variable note due in 2035 issued by Mobil Services (Bahamas) Ltd. was assigned to a consolidated ExxonMobil affiliate. This note is no longer classified as third party long-term debt. This assignment did not result in a “Reduction in long-term debt” on the Statement of Cash Flows.

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

	2014	2013	2012
	(millions of dollars)
Cash payments for interest	380	426	555
Cash payments for income taxes	18,085	25,066	24,349

XML

Additional Working Capital Information

12 Months Ended

Dec. 31, 2014

Additional Working Capital Information [Abstract]

Additional Working Capital Information

6. Additional Working Capital Information

			Dec. 31	Dec. 31
			2014	2013
			(millions of dollars)
Notes and accounts receivable
	Trade, less reserves of $113 million and $112 million		18,541	25,993
	Other, less reserves of $48 million and $28 million		9,468	7,159
		Total	28,009	33,152
Notes and loans payable
	Bank loans		473	723
	Commercial paper		16,225	14,051
	Long-term debt due within one year		770	1,034
		Total	17,468	15,808
Accounts payable and accrued liabilities
	Trade payables		25,286	30,920
	Payables to equity companies		6,589	6,587
	Accrued taxes other than income taxes		3,290	3,883
	Other		7,062	6,695
		Total	42,227	48,085

The Corporation has short-term committed lines of credit of $6.3 billion which were unused as of December 31, 2014. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was0.3 percent and 0.4 percent at December31,2014, and 2013, respectively.

XML

Investments, Advances And Long-Term Receivables

12 Months Ended

Dec. 31, 2014

Investments, Advances And Long-Term Receivables [Abstract]

Investments, Advances And Long-Term Receivables

8. Investments, Advances and Long-Term Receivables

			Dec. 31,	Dec. 31,
			2014	2013
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,017	19,619
	Advances		9,818	10,476
		Total equity company investments and advances	29,835	30,095
Companies carried at cost or less and stock investments carried at fair value			526	115
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $2,662 million and $2,938 million		4,878	6,118
		Total	35,239	36,328

XML

Accounting For Suspended Exploratory Well Costs (Schedule Of Additional Detail For The Projects) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	3,587	$ 2,707	$ 2,679	$ 2,881
Total 38 Projects [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	1,035
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	8
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	12
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	38
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
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	28
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
Malaysia [Member] | Project In Malaysia - Besar [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	18
Malaysia [Member] | Project In Malaysia - Besar [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	1992
Malaysia [Member] | Project In Malaysia - Besar [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2010
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 - Owowo [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	50
Nigeria [Member] | Project In Nigeria - Owowo [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2009
Nigeria [Member] | Project In Nigeria - Owowo [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2012
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	15
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	18
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	29
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	2013
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
Papua New Guinea [Member] | Project in Papua New Guinea - P'nyang [Member]
Exploratory Wells Drilled [Line Items]
Capitalized exploratory well costs	58
Papua New Guinea [Member] | Project in Papua New Guinea - P'nyang [Member] | Minimum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2012
Papua New Guinea [Member] | Project in Papua New Guinea - P'nyang [Member] | Maximum [Member]
Exploratory Wells Drilled [Line Items]
Years wells drilled, period	2012
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

XML

Pension And Other Postretirement Benefits (Fair Value Of Benefit Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Insurance contracts at contract value	$ 11		$ 12
Fair value of plan assets	12,915		11,190		12,632
Pension Benefits - U.S. [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,331		2,514
Pension Benefits - U.S. [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,144		2,622
Pension Benefits - U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	562		523
Pension Benefits - U.S. [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,841		3,430
Pension Benefits - U.S. [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,890		2,056
Pension Benefits - U.S. [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5		6
Pension Benefits - U.S. [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	131		27
Pension Benefits - U.S. [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,904		11,178
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,331	[1]	2,514	[1]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,144	[1]	2,622	[1]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,841	[2]	3,430	[2]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,890	[2]	2,056	[2]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	5	[2]	6	[2]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	131	[3]	27	[3]
Pension Benefits - U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	12,342		10,655
Pension Benefits - U.S. [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	562	[4]	523	[4]
Pension Benefits - U.S. [Member] | Significant Unobservable Inputs (Level 3) [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	562		523
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Insurance contracts at contract value	27		20
Fair value of plan assets	20,095		19,283		18,090
Pension Benefits - Non-U.S. [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,284		3,046
Pension Benefits - Non-U.S. [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	4,005		5,902
Pension Benefits - Non-U.S. [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	535		502
Pension Benefits - Non-U.S. [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,686		2,125
Pension Benefits - Non-U.S. [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,299		7,372
Pension Benefits - Non-U.S. [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	146		103
Pension Benefits - Non-U.S. [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	57		136
Pension Benefits - Non-U.S. [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56		77
Pension Benefits - Non-U.S. [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	20,068		19,263
Pension Benefits - Non-U.S. [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	229	[5]	294	[5]
Pension Benefits - Non-U.S. [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	249	[6]	272	[6]
Pension Benefits - Non-U.S. [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	25		57
Pension Benefits - Non-U.S. [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	503		623
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,284	[1]	3,046	[1]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Non-U.S. Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	3,776	[1]	5,608	[1]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2,686	[2]	2,125	[2]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Government Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	9,050	[2]	7,100	[2]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Asset-Backed Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	146	[2]	103	[2]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	31	[7]	20	[7]
Pension Benefits - Non-U.S. [Member] | Significant Other Observable Inputs (Level 2) [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	18,973		18,002
Pension Benefits - Non-U.S. [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	535	[4]	502	[4]
Pension Benefits - Non-U.S. [Member] | Significant Unobservable Inputs (Level 3) [Member] | Real Estate Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	57	[8]	136	[8]
Pension Benefits - Non-U.S. [Member] | Significant Unobservable Inputs (Level 3) [Member] | Total At Fair Value [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 592		$ 638

[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.

XML

Leased Facilities (Leased Facilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Leased Facilities [Abstract]
Lease Payments Under Minimum Commitments, 2015	$ 2,034
Lease Payments Under Minimum Commitments, 2016	1,379
Lease Payments Under Minimum Commitments, 2017	774
Lease Payments Under Minimum Commitments, 2018	418
Lease Payments Under Minimum Commitments, 2019	312
Lease Payments Under Minimum Commitments, 2020 and beyond	1,296
Lease Payments Under Minimum Commitments, Total	6,213
Related Sublease Rental Income, 2015	31
Related Sublease Rental Income, 2016	7
Related Sublease Rental Income, 2017	6
Related Sublease Rental Income, 2018	3
Related Sublease Rental Income, 2019	3
Related Sublease Rental Income, 2020 and beyond	20
Related Sublease Rental Income, Total	$ 70

XML

Accounting For Suspended Exploratory Well Costs (Schedule Of Number Of Projects With Suspended Exploratory Well Costs) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting For Suspended Exploratory Well Costs [Abstract]
Number of projects with first capitalized well drilled in the preceding 12 months	8	8	10
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months	53	50	45
Total	61	58	55

XML

Disclosures About Segments And Related Information (Schedule Of Segments And Related Information) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Earnings after income tax	$ 32,520		$ 32,580		$ 44,880
Earnings of equity companies included above	13,323		13,927		15,010
Sales and other operating revenue	394,105	[1],[2]	420,836	[1],[2]	451,509	[1],[2]
Depreciation and depletion expense	17,297		17,182		15,888
Interest revenue	75		87		117
Interest expense	286		9		327
Income taxes	18,015		24,263		31,045
Additions to property, plant and equipment	34,256		37,741		35,179
Investments in equity companies	20,017		19,619		18,530
Total assets	349,493		346,808		333,795
U.S. [Member]
Income taxes	1,862		1,391		3,579
Non-U.S. [Member]
Income taxes	16,153		22,872		27,466
Upstream [Member] | U.S. [Member]
Earnings after income tax	5,197		4,191		3,925
Earnings of equity companies included above	1,235		1,576		1,759
Sales and other operating revenue	14,826	[2]	13,712	[2]	11,039	[2]
Intersegment revenue	7,723		8,343		8,764
Depreciation and depletion expense	5,139		5,170		5,104
Interest expense	40		30		37
Income taxes	1,300		2,197		2,025
Additions to property, plant and equipment	9,098		7,480		9,697
Investments in equity companies	5,089		4,975		4,020
Total assets	92,555		88,698		86,146
Upstream [Member] | Non-U.S. [Member]
Earnings after income tax	22,351		22,650		25,970
Earnings of equity companies included above	10,859		11,627		11,900
Sales and other operating revenue	22,336	[2]	25,349	[2]	27,673	[2]
Intersegment revenue	38,846		45,761		47,507
Depreciation and depletion expense	8,523		8,277		7,340
Interest expense	17		26		13
Income taxes	15,165		21,554		25,362
Additions to property, plant and equipment	19,225		26,075		21,769
Investments in equity companies	10,877		9,740		9,147
Total assets	161,033		157,465		140,848
Downstream [Member] | U.S. [Member]
Earnings after income tax	1,618		2,199		3,575
Earnings of equity companies included above	29		(460)		6
Sales and other operating revenue	118,771	[2]	123,802	[2]	125,088	[2]
Intersegment revenue	17,281		20,781		20,963
Depreciation and depletion expense	654		633		594
Interest expense	6		7		3
Income taxes	610		721		1,811
Additions to property, plant and equipment	1,050		616		480
Investments in equity companies	69		62		195
Total assets	18,371		19,261		18,451
Downstream [Member] | Non-U.S. [Member]
Earnings after income tax	1,427		1,250		9,615
Earnings of equity companies included above	82		22		387
Sales and other operating revenue	199,976	[2]	218,904	[2]	248,959	[2]
Intersegment revenue	44,231		52,624		62,130
Depreciation and depletion expense	1,228		1,390		1,280
Interest expense	4		8		36
Income taxes	968		481		1,892
Additions to property, plant and equipment	1,356		1,072		1,153
Investments in equity companies	1,006		1,749		2,069
Total assets	33,299		40,661		40,956
Chemical [Member] | U.S. [Member]
Earnings after income tax	2,804		2,755		2,220
Earnings of equity companies included above	186		189		183
Sales and other operating revenue	15,115	[2]	15,295	[2]	14,723	[2]
Intersegment revenue	10,117		11,993		12,409
Depreciation and depletion expense	370		378		376
Interest expense			1
Income taxes	1,032		989		755
Additions to property, plant and equipment	1,564		840		338
Investments in equity companies	258		217		233
Total assets	8,798		7,816		7,238
Chemical [Member] | Non-U.S. [Member]
Earnings after income tax	1,511		1,073		1,678
Earnings of equity companies included above	1,377		1,422		1,267
Sales and other operating revenue	23,063	[2]	23,753	[2]	24,003	[2]
Intersegment revenue	8,098		8,232		9,750
Depreciation and depletion expense	645		632		508
Interest expense					(1)
Income taxes	358		363		232
Additions to property, plant and equipment	564		272		659
Investments in equity companies	3,026		3,103		3,143
Total assets	18,449		19,659		18,886
Corporate And Financing [Member]
Earnings after income tax	(2,388)		(1,538)		(2,103)
Earnings of equity companies included above	(445)		(449)		(492)
Sales and other operating revenue	18	[2]	21	[2]	24	[2]
Intersegment revenue	274		285		258
Depreciation and depletion expense	738		702		686
Interest revenue	75		87		117
Interest expense	219		(63)		239
Income taxes	(1,418)		(2,042)		(1,032)
Additions to property, plant and equipment	1,399		1,386		1,083
Investments in equity companies	(308)		(227)		(277)
Total assets	$ 16,988		$ 13,248		$ 21,270

[1] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012.

[2] Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

XML

Investments, Advances And Long-Term Receivables (Tables)

12 Months Ended

Dec. 31, 2014

Investments, Advances And Long-Term Receivables [Abstract]

Schedule Of Investments, Advances And Long-Term Receivables

			Dec. 31,	Dec. 31,
			2014	2013
			(millions of dollars)
Companies carried at equity in underlying assets
	Investments		20,017	19,619
	Advances		9,818	10,476
		Total equity company investments and advances	29,835	30,095
Companies carried at cost or less and stock investments carried at fair value			526	115
Long-term receivables and miscellaneous investments at cost or less, net of reserves
	of $2,662 million and $2,938 million		4,878	6,118
		Total	35,239	36,328

XML

Additional Working Capital Information (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Line Of Credit Facility [Line Items]
Weighted-average interest rate on short-term borrowings outstanding	0.30%	0.40%
Short Term Financing [Member]
Line Of Credit Facility [Line Items]
Unused credit lines	6,300

XML

Financial Instruments And Derivatives

12 Months Ended

Dec. 31, 2014

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 $11.7 billion and $6.8 billion at December 31, 2014, and 2013, respectively, as compared to recorded book values of $11.3 billion and $6.5 billion at December 31, 2014, and 2013, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $5,500 million of long-term debt in the first quarter of 2014.

The fair value of long-term debt by hierarchy level at December 31, 2014, is: Level 1 $11,036 million; Level 2 $561 million; and Level 3 $63 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 $75 million at year-end 2014 and a net asset of $1 million at year-end 2013. 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 $110 million, $(7) million and $(23) million during 2014, 2013 and 2012, 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.

XML

Disclosures About Segments And Related Information

12 Months Ended

Dec. 31, 2014

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 $129 million and $202 million in 2014 and 2012, 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, 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
As of December 31, 2012
Earnings after income tax		3,925		25,970		3,575		9,615		2,220		1,678		(2,103)		44,880
Earnings of equity companies included above		1,759		11,900		6		387		183		1,267		(492)		15,010
Sales and other operating revenue (1)		11,039		27,673		125,088		248,959		14,723		24,003		24		451,509
Intersegment revenue		8,764		47,507		20,963		62,130		12,409		9,750		258		-
Depreciation and depletion expense		5,104		7,340		594		1,280		376		508		686		15,888
Interest revenue		-		-		-		-		-		-		117		117
Interest expense		37		13		3		36		-		(1)		239		327
Income taxes		2,025		25,362		1,811		1,892		755		232		(1,032)		31,045
Additions to property, plant and equipment		9,697		21,769		480		1,153		338		659		1,083		35,179
Investments in equity companies		4,020		9,147		195		2,069		233		3,143		(277)		18,530
Total assets		86,146		140,848		18,451		40,956		7,238		18,886		21,270		333,795

(1) Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

Geographic
Sales and other operating revenue (1)		2014	2013	2012
		(millions of dollars)
United States		148,713	152,820	150,865
Non-U.S.		245,392	268,016	300,644
	Total	394,105	420,836	451,509
Significant non-U.S. revenue sources include:
	Canada	36,072	35,924	34,325
	United Kingdom	31,346	34,061	33,600
	Belgium	20,953	20,973	23,567
	Italy	18,880	19,273	18,228
	France	17,639	18,444	19,601
	Singapore	15,407	15,623	14,606
	Germany	14,816	15,701	15,871

(1) Sales and other operating revenue includes sales-based taxes of $29,342 million for 2014, $30,589 million for 2013 and $32,409 million for 2012. See Note 1, Summary of Accounting Policies.

Long-lived assets		2014	2013	2012
		(millions of dollars)
United States		104,000	98,271	94,336
Non-U.S.		148,668	145,379	132,613
	Total	252,668	243,650	226,949
Significant non-U.S. long-lived assets include:
	Canada	43,858	41,522	31,979
	Australia	15,328	14,258	13,415
	Nigeria	12,265	12,343	12,216
	Singapore	9,620	9,570	9,700
	Kazakhstan	9,138	8,530	7,785
	Angola	9,057	8,262	8,238
	Papua New Guinea	6,099	5,768	4,599
	Norway	5,139	6,542	7,040

XML

Income, Sales-Based And Other Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income, Sales-Based And Other Taxes [Abstract]
Net deferred income tax expense (credits)/charges for tax rate and law changes	$ (40,000,000)	$ (310,000,000)	$ 244,000,000
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	30.00%
Credit of net interest expense on income tax reserves		207,000,000
Interest expense on income tax reserves	42,000,000		46,000,000
Interest payable on income tax reserves	205,000,000	156,000,000
Statement [Line Items]
Asset valuation allowances	2,570,000,000	2,491,000,000
Valuation Allowance increase from 2013 to 2014	79,000,000
Additional net provisions [Member]
Statement [Line Items]
Valuation Allowance increase from 2013 to 2014	340,000,000
Effects of foreign currency translation [Member]
Statement [Line Items]
Valuation Allowance increase from 2013 to 2014	$ (261,000,000)

XML

Other Comprehensive Income Information (Schedule Of Income Tax (Expense)/Credit For Components Of Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Comprehensive Income Information Tax [Abstract]
Foreign exchange translation adjustment	$ 292	$ 218	$ (236)
Postretirement benefits reserves adjustment (excluding amortization)	2,009	(1,540)	1,619
Amortization and settlement of postretirement benefits reserves adjustment included in net periodic benefit costs	(460)	(796)	(1,226)
Unrealized change in fair value of stock investments	34
Realized change in fair value of stock investments included in net income	(2)
Total	$ 1,873	$ (2,118)	$ 157

XML

Litigation And Other Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Litigation And Other Contingencies [Abstract]

Schedule Of Guarantees

						Dec. 31, 2014
			Equity Company		Other Third-Party
			Obligations (1)		Obligations		Total
					(millions of dollars)
Guarantees
	Debt-related			3,506		41	3,547
	Other			2,920		3,982	6,902
		Total		6,426		4,023	10,449
(1) ExxonMobil share.

Unconditional Purchase Obligations

	Payments Due by Period
		2016-	2020 and
	2015	2019	Beyond		Total
	(millions of dollars)
Unconditional purchase obligations (1)	150	608		337	1,095

(1) Undiscounted obligations of $1,095million mainly pertain to pipeline throughput agreements and include $433million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $168million, totaled $927million.

XML

Consolidated Balance Sheet (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 4,616	$ 4,644
Cash and cash equivalents - restricted	42	269
Notes and accounts receivable, less estimated doubtful amounts	28,009	33,152
Inventories
Crude oil, products and merchandise	12,384	12,117
Materials and supplies	4,294	4,018
Other current assets	3,565	5,108
Total current assets	52,910	59,308
Investments, advances and long-term receivables	35,239	36,328
Property, plant and equipment, at cost, less accumulated depreciation and depletion	252,668	243,650
Other assets, including intangibles, net	8,676	7,522
Total assets	349,493	346,808
Current liabilities
Notes and loans payable	17,468	15,808
Accounts payable and accrued liabilities	42,227	48,085
Income taxes payable	4,938	7,831
Total current liabilities	64,633	71,724
Long-term debt	11,653	6,891
Postretirement benefits reserves	25,802	20,646
Deferred income tax liabilities	39,230	40,530
Long-term obligations to equity companies	5,325	4,742
Other long-term obligations	21,786	21,780
Total liabilities	168,429	166,313
Commitments and contingencies (Note 16)
Equity
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued)	10,792	10,077
Earnings reinvested	408,384	387,432
Accumulated other comprehensive income	(18,957)	(10,725)
Common stock held in treasury (3,818 million shares in 2014 and 3,684 million shares in 2013)	(225,820)	(212,781)
ExxonMobil share of equity	174,399	174,003
Noncontrolling interests	6,665	6,492
Total equity	181,064	180,495
Total liabilities and equity	$ 349,493	$ 346,808

XML

Pension And Other Postretirement Benefits (Pension Plans With Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Funded Pension Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 17,505	$ 14,737
Accumulated benefit obligation	14,493	12,342
Fair value of plan assets	12,915	11,189
Funded Pension Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	5,031	891
Accumulated benefit obligation	4,590	689
Fair value of plan assets	3,890	611
Unfunded Pension Plans [Member] | Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	3,024	2,567
Accumulated benefit obligation	1,892	1,647
Unfunded Pension Plans [Member] | Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	7,839	7,133
Accumulated benefit obligation	$ 6,573	$ 6,070

XML

Accounting Changes

12 Months Ended

Dec. 31, 2014

Accounting Changes [Abstract]

Accounting Changes

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2014 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, 2017. ExxonMobil is evaluating the standard and its effect on the Corporation’s financial statements. 

XML

Property, Plant And Equipment And Asset Retirement Obligations (Property, Plant And Equipment) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	$ 446,789	$ 434,517
Property, Plant and Equipment, Net	252,668	243,650	226,949
Upstream [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	347,170	336,359
Property, Plant and Equipment, Net	205,308	197,554
Downstream [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	53,327	54,456
Property, Plant and Equipment, Net	22,639	23,219
Chemical [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	30,717	29,487
Property, Plant and Equipment, Net	14,918	13,965
Other [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost	15,575	14,215
Property, Plant and Equipment, Net	$ 9,803	$ 8,912

XML

Pension And Other Postretirement Benefits (Assets Recorded In Balance Sheet And Other Comprehensive Income) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Postretirement benefits reserves	$ (25,802)		$ (20,646)
Pension Benefits - U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	(7,614)	[1]	(6,114)	[1]
Other assets			1
Current liabilities	(340)		(275)
Postretirement benefits reserves	(7,274)		(5,840)
Total recorded	(7,614)		(6,114)
Net actuarial loss/(gain)	6,589		4,780
Prior service cost	27		60
Total recorded in accumulated other comprehensive income	6,616		4,840
Pension Benefits - Non-U.S. [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	(9,952)	[1]	(8,074)	[1]
Other assets	302		201
Current liabilities	(325)		(358)
Postretirement benefits reserves	(9,929)		(7,917)
Total recorded	(9,952)		(8,074)
Net actuarial loss/(gain)	9,642		7,943
Prior service cost	429		665
Total recorded in accumulated other comprehensive income	10,071		8,608
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance at December 31	(8,968)	[1]	(7,248)	[1]
Current liabilities	(369)		(359)
Postretirement benefits reserves	(8,599)		(6,889)
Total recorded	(8,968)		(7,248)
Net actuarial loss/(gain)	2,997		1,603
Prior service cost	51		65
Total recorded in accumulated other comprehensive income	$ 3,048		$ 1,668

[1] Fair value of assets less benefit obligation shown on the preceding page.

XML

Financial Instruments And Derivatives (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		$ 11,700	$ 6,800
Recorded book values of total long-term debt, excluding capitalized lease obligations		11,300	6,500
Derivative asset at fair value, net		75	1
Gain (loss) before-tax earnings impact of derivatives		110	(7)	(23)
Additions to long-term debt	5,500	5,731	345	995
Level 1 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		11,036
Level 2 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		561
Level 3 [Member]
Financial Instruments And Derivatives [Line Items]
Estimated fair value of total long-term debt, excluding capitalized lease obligations		$ 63

XML

Income, Sales-Based And Other Taxes

12 Months Ended

Dec. 31, 2014

Income, Sales-Based And Other Taxes [Abstract]

Income, Sales-Based And Other Taxes

19. Income, Sales-Based and Other Taxes

						2014				2013				2012
				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		1,456		14,755	16,211	1,073		22,115	23,188	1,791		25,650	27,441
		Deferred - net		900		1,398	2,298	(116)		757	641	1,097		1,816	2,913
	U.S. tax on non-U.S. operations			5		-	5	37		-	37	89		-	89
			Total federal and non-U.S.	2,361		16,153	18,514	994		22,872	23,866	2,977		27,466	30,443
	State (1)			(499)		-	(499)	397		-	397	602		-	602
			Total income tax expense	1,862		16,153	18,015	1,391		22,872	24,263	3,579		27,466	31,045
Sales-based taxes				6,310		23,032	29,342	5,992		24,597	30,589	5,785		26,624	32,409
All other taxes and duties
	Other taxes and duties			378		31,908	32,286	955		32,275	33,230	1,406		34,152	35,558
	Included in production and
		manufacturing expenses		1,454		1,179	2,633	1,318		1,182	2,500	1,242		1,308	2,550
	Included in SG&A expenses			155		441	596	150		516	666	154		595	749
		Total other taxes and duties		1,987		33,528	35,515	2,423		33,973	36,396	2,802		36,055	38,857
			Total	10,159		72,713	82,872	9,806		81,442	91,248	12,166		90,145	102,311

(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 net credits of $40 million in 2014 and $310 million in 2013 and a netcharge of $244 million in 2012 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 for2014, 2013 and2012 is as follows:

			2014	2013	2012
			(millions of dollars)
Income before income taxes
	United States		9,080	9,746	11,222
	Non-U.S.		42,550	47,965	67,504
		Total	51,630	57,711	78,726
Theoretical tax			18,071	20,199	27,554
Effect of equity method of accounting			(4,663)	(4,874)	(5,254)
Non-U.S. taxes in excess of theoretical U.S. tax			5,442	10,528	8,434
U.S. tax on non-U.S. operations			5	37	89
State taxes, net of federal tax benefit			(324)	258	391
Other			(516)	(1,885)	(169)
		Total income tax expense	18,015	24,263	31,045
Effective tax rate calculation
Income taxes			18,015	24,263	31,045
ExxonMobil share of equity company income taxes			5,678	6,061	5,859
		Total income taxes	23,693	30,324	36,904
Net income including noncontrolling interests			33,615	33,448	47,681
		Total income before taxes	57,308	63,772	84,585
Effective income tax rate			41%	48%	44%

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:		2014	2013
		(millions of dollars)
Property, plant and equipment		51,643	50,884
Other liabilities		4,359	3,474
	Total deferred tax liabilities	56,002	54,358
Pension and other postretirement benefits		(8,140)	(6,573)
Asset retirement obligations		(6,162)	(6,083)
Tax loss carryforwards		(4,099)	(3,393)
Other assets		(6,446)	(6,246)
	Total deferred tax assets	(24,847)	(22,295)
Asset valuation allowances		2,570	2,491
	Net deferred tax liabilities	33,725	34,554

In 2014, asset valuation allowances of $2,570 million increased by $79 million and included additional net provisions of $340 million and effects of foreign currency translation of $(261) 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		2014	2013
		(millions of dollars)
Other current assets		(2,001)	(3,575)
Other assets, including intangibles, net		(3,955)	(2,822)
Accounts payable and accrued liabilities		451	421
Deferred income tax liabilities		39,230	40,530
	Net deferred tax liabilities	33,725	34,554

The Corporation had $51 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

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		2014	2013	2012
		(millions of dollars)
Balance at January 1		7,838	7,663	4,922
	Additions based on current year's tax positions	1,454	1,460	1,662
	Additions for prior years' tax positions	448	464	2,559
	Reductions for prior years' tax positions	(532)	(249)	(535)
	Reductions due to lapse of the statute of limitations	(117)	(588)	(79)
	Settlements with tax authorities	(43)	(849)	(855)
	Foreign exchange effects/other	(62)	(63)	(11)
Balance at December 31		8,986	7,838	7,663

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 2014, 2013 and 2012 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. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 30 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 - 2014
Angola	2009 - 2014
Australia:	2000 - 2003
	2005
	2008 - 2014
Canada	2007 - 2014
Equatorial Guinea	2007 - 2014
Malaysia	2008 - 2014
Nigeria	2004 - 2014
Norway	2005 - 2014
Qatar	2008 - 2014
Russia	2011 - 2014
United Kingdom	2010 - 2014
United States	2006 - 2014

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 $42 million in interest expense on income tax reserves in 2014. 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 Corporation incurred $46 million in interest expense in 2012.The related interest payable balances were $205 million and $156 million at December 31, 2014, and 2013, respectively.

XML

Incentive Program (Grant Value Of Restricted Stock And Units) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Grant price, per share	$ 95.2	$ 94.47	$ 87.24
Restricted stock and units settled in stock	$ 858	$ 843	$ 797
Units settled in cash	73	76	77
Total value	$ 931	$ 919	$ 874

XML

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share Computation

	2014	2013	2012
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	32,520	32,580	44,880
Weighted average number of common shares outstanding(millions of shares)	4,282	4,419	4,628
Earnings per common share(dollars) (1)	7.60	7.37	9.70
Dividends paid per common share (dollars)	2.70	2.46	2.18

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

XML

Earnings Per Share

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Share

12. Earnings Per Share

	2014	2013	2012
Earnings per common share
Net income attributable to ExxonMobil(millions of dollars)	32,520	32,580	44,880
Weighted average number of common shares outstanding(millions of shares)	4,282	4,419	4,628
Earnings per common share(dollars) (1)	7.60	7.37	9.70
Dividends paid per common share (dollars)	2.70	2.46	2.18

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

XML

Income, Sales-Based And Other Taxes (Remaining Tax Years Subject To Examination By Major Tax Jurisdiction) (Details)	12 Months Ended
	Dec. 31, 2014
Abu Dhabi [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
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	2014
Angola [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2009
Australia [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2003
Australia [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2000
Australia Second Range [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2005
Australia Second Range [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2005
Australia Third Range [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
Australia Third 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	2014
Canada [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2007
Equatorial Guinea [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
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	2014
Malaysia [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2008
Nigeria [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
Nigeria [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2004
Norway [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
Norway [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2005
Qatar [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
Qatar [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2008
Russia [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
Russia [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2011
United Kingdom [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
United Kingdom [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2010
United States [Member] | Maximum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2014
United States [Member] | Minimum [Member]
Income, Sales-Based and Other Taxes [Line Items]
Open Tax Years by major tax jurisdiction	2006