SEC Form 10-K Filing Report

Company: EXXON MOBIL CORP
CIK: 34088
SIC Code: 2911
Filing Date: 2013-02-27 00:00:00
Market Capitalization: 408197973.22439575

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ITEM 1. BUSINESS
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. ExxonMobil also has interests in electric power generation facilities. 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 2012 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.5 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 have a modest increase in 2013 and 2014 (with capital expenditures approximately 45 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 2012. For technology licensed to third parties, revenues totaled approximately $176 million in 2012. 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 76.9 thousand, 82.1 thousand and 83.6 thousand at years ended 2012, 2011 and 2010, 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 11.1 thousand, 17.0 thousand and 20.1 thousand at years ended 2012, 2011 and 2010, 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 “

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ITEM 1A. RISK FACTORS
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. As a U.S. company, ExxonMobil is subject to laws prohibiting U.S. companies from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to our non-U.S. competitors unless their own home countries impose comparable restrictions.
Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory 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.
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 or other legal proceedings, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur.
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 fuel-producing algae. 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.
The term “project” as used in this report does not necessarily have the same meaning as under SEC Rule 13q-1 relating to government payment reporting. For example, a single project for purposes of the rule may encompass numerous properties, agreements, investments, developments, phases, work efforts, activities, and components, each of which we may also informally describe as a “project”.
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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
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 2012
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, 2012, 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
1,228
-
-
14,471
3,901
Canada/South America (1)
1,378
Europe
-
-
2,526
Africa
-
-
1,140
Asia
-
-
5,150
1,938
Australia/Oceania
-
-
1,012
Total Consolidated
3,368
24,643
9,330
Equity Companies
United States
-
-
Europe
-
-
-
7,057
1,204
Asia
1,009
-
-
18,431
4,495
Total Equity Company
1,295
-
-
25,614
5,984
Total Developed
4,663
1,133
50,257
15,314
Undeveloped
Consolidated Subsidiaries
United States
-
-
11,744
2,878
Canada/South America (1)
3,017
-
3,222
Europe
-
-
Africa
-
-
Asia
-
-
-
Australia/Oceania
-
-
6,556
1,227
Total Consolidated
2,156
3,017
-
20,088
8,839
Equity Companies
United States
-
-
Europe
-
-
-
-
2,478
Asia
-
-
1,239
Total Equity Company
-
-
3,746
1,011
Total Undeveloped
2,489
3,017
-
23,834
9,850
Total Proved Reserves
7,152
1,505
3,560
74,091
25,164
(1) South America includes proved developed reserves of 0.4 million barrels of crude oil and natural gas liquids and 57 billion cubic feet of natural gas and proved undeveloped reserves of 0.6 million barrels of crude oil and natural gas liquids and 65 billion cubic feet of natural gas.
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 period 2013-2017. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, 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 2012
Additions to ExxonMobil’s proved reserves in 2012 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 2-D and 3-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 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 several have served on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers.
The Global Reserves group maintains a central database containing the official company global reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Global Reserves group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.
2. Proved Undeveloped Reserves
At year-end 2012, approximately 9.9 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 39 percent of the 25.2 GOEB reported in proved reserves. This compares to the 8.8 GOEB of proved undeveloped reserves reported at the end of 2011. The net increase is primarily due to the addition of new projects in
Canada and the United States. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 0.5 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to completion of drilling and the initiation of production activities in unconventional fields in the United States and on new pad locations in the Cold Lake field in Canada.
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 first recording of proved reserves to the start of production of these reserves. However, the development time for large and complex projects can exceed five years. During 2012, discoveries and extensions related to new projects added approximately 1.3 GOEB of proved undeveloped reserves. The largest of these additions were related to planned drilling in the United States. Overall, investments of $24.8 billion were made by the Corporation during 2012 to progress the development of reported proved undeveloped reserves, including $21.7 billion for oil and gas producing activities and an additional $3.1 billion for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 69 percent of the $36.1 billion in total reported Upstream capital and exploration expenditures.
Proved undeveloped reserves in Canada, Kazakhstan, the United States, and the Netherlands have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and 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 and regulatory approvals. Of the proved undeveloped reserves that have been reported for five or more years, 57 percent are contained in four fields in Canada, Kazakhstan and the Netherlands. The largest of these is related to the Kearl project in Canada, where construction of the initial development was completed during 2012 and phased start-up activities were under way. In Kazakhstan, the proved undeveloped reserves are related to 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. The fourth field is the Groningen gas field in the Netherlands. Proved undeveloped reserves reported for this field 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. The remainder of proved undeveloped reserves are contained in over 140 fields in 16 countries.
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.
(thousands of barrels daily)
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States
Canada/South America (1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
1,516
1,629
1,762
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total crude oil and natural gas liquids production
1,993
2,125
2,240
Bitumen production
Consolidated Subsidiaries
Canada/South America
Synthetic oil production
Consolidated Subsidiaries
Canada/South America
Total liquids production
2,185
2,312
2,422
(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States
3,819
3,917
2,595
Canada/South America (1)
Europe
1,446
1,701
1,859
Africa
Asia
1,445
1,879
1,847
Australia/Oceania
Total Consolidated Subsidiaries
7,452
8,247
7,216
Equity Companies
United States
-
Europe
1,774
1,747
1,977
Asia
3,093
3,168
2,954
Total Equity Companies
4,870
4,915
4,932
Total natural gas production available for sale
12,322
13,162
12,148
(thousands of oil-equivalent barrels daily)
Oil-equivalent production
4,239
4,506
4,447
(1) South America includes liquids production for 2012, 2011 and 2010 of one thousand barrels daily for each year and natural gas production available for sale for 2012, 2011 and 2010 of 38 million, 45 million, and 52 million cubic feet daily, respectively.
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 2012
(dollars per unit)
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel
84.51
91.45
104.14
110.11
102.19
93.39
100.29
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 and NGL, per barrel
103.94
-
104.59
-
101.60
-
101.94
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 and NGL, per barrel
87.43
91.45
104.15
110.11
101.88
93.39
100.68
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
During 2011
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel
90.65
97.10
102.20
109.69
98.79
96.28
100.79
Natural gas, per thousand cubic feet
3.45
3.29
9.32
2.83
3.37
3.98
4.65
Bitumen, per barrel
-
64.65
-
-
-
-
64.65
Synthetic oil, per barrel
-
102.80
-
-
-
-
102.80
Average production costs, per oil-equivalent barrel - total
11.14
23.58
13.58
14.04
6.58
12.85
12.33
Average production costs, per barrel - bitumen
-
19.80
-
-
-
-
19.80
Average production costs, per barrel - synthetic oil
-
47.68
-
-
-
-
47.68
Equity Companies
Average production prices
Crude oil and NGL, per barrel
104.44
-
103.23
-
100.14
-
100.74
Natural gas, per thousand cubic feet
5.08
-
8.61
-
7.78
-
8.08
Average production costs, per oil-equivalent barrel - total
19.96
-
2.92
-
1.09
-
2.45
Total
Average production prices
Crude oil and NGL, per barrel
92.80
97.10
102.22
109.69
99.50
96.28
100.78
Natural gas, per thousand cubic feet
3.45
3.29
8.96
2.83
6.14
3.98
5.93
Bitumen, per barrel
-
64.65
-
-
-
-
64.65
Synthetic oil, per barrel
-
102.80
-
-
-
-
102.80
Average production costs, per oil-equivalent barrel - total
11.68
23.58
9.85
14.04
3.41
12.85
9.45
Average production costs, per barrel - bitumen
-
19.80
-
-
-
-
19.80
Average production costs, per barrel - synthetic oil
-
47.68
-
-
-
-
47.68
United
Canada/
Australia/
States
S. America
Europe
Africa
Asia
Oceania
Total
During 2010
(dollars per unit)
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel
70.22
69.92
73.37
78.08
72.96
68.91
74.04
Natural gas, per thousand cubic feet
3.92
3.41
6.44
2.15
3.19
3.31
4.31
Bitumen, per barrel
-
56.61
-
-
-
-
56.61
Synthetic oil, per barrel
-
78.42
-
-
-
-
78.42
Average production costs, per oil-equivalent barrel - total
9.92
20.07
11.62
9.63
5.65
11.20
10.54
Average production costs, per barrel - bitumen
-
17.81
-
-
-
-
17.81
Average production costs, per barrel - synthetic oil
-
42.79
-
-
-
-
42.79
Equity Companies
Average production prices
Crude oil and NGL, per barrel
74.70
-
74.14
-
72.67
-
72.98
Natural gas, per thousand cubic feet
8.30
-
6.91
-
5.42
-
6.02
Average production costs, per oil-equivalent barrel - total
19.11
-
2.41
-
0.98
-
2.31
Total
Average production prices
Crude oil and NGL, per barrel
70.98
69.92
73.38
78.08
72.80
68.91
73.81
Natural gas, per thousand cubic feet
3.92
3.41
6.68
2.15
4.56
3.31
5.00
Bitumen, per barrel
-
56.61
-
-
-
-
56.61
Synthetic oil, per barrel
-
78.42
-
-
-
-
78.42
Average production costs, per oil-equivalent barrel - total
10.67
20.07
8.46
9.63
2.91
11.20
8.14
Average production costs, per barrel - bitumen
-
17.81
-
-
-
-
17.81
Average production costs, per barrel - synthetic oil
-
42.79
-
-
-
-
42.79
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.
4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States
Canada/South America
Europe
Africa
Asia
-
Australia/Oceania
Total Consolidated Subsidiaries
Equity Companies
United States
-
-
Europe
Asia
-
-
-
Total Equity Companies
Total productive exploratory wells drilled
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States
Canada/South America
-
-
Europe
-
Africa
-
-
Asia
Australia/Oceania
-
Total Consolidated Subsidiaries
Equity Companies
United States
-
-
-
Europe
-
-
Asia
-
-
-
Total Equity Companies
-
-
Total dry exploratory wells drilled
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States
1,069
Canada/South America
Europe
Africa
Asia
Australia/Oceania
-
-
Total Consolidated Subsidiaries
1,017
1,304
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total productive development wells drilled
1,310
1,554
1,200
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States
Canada/South America
-
-
-
Europe
-
Africa
-
-
Asia
-
Australia/Oceania
-
-
Total Consolidated Subsidiaries
Equity Companies
United States
-
-
-
Europe
-
-
-
Asia
-
-
-
Total Equity Companies
-
-
-
Total dry development wells drilled
Total number of net wells drilled
1,342
1,606
1,249
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 2012, the company’s share of net production of synthetic crude oil was about 69 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, and is expected to be developed in two phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline. At year-end 2012, the construction of the initial development of the Kearl project was complete and phased start-up activities were under way. Construction on the Kearl Expansion project continued during 2012.
5. Present Activities
A. Wells Drilling
Year-End 2012
Year-End 2011
Gross
Net
Gross
Net
Wells Drilling
Consolidated Subsidiaries
United States
1,099
1,276
Canada/South America
Europe
Africa
Asia
Australia/Oceania
Total Consolidated Subsidiaries
1,427
1,530
Equity Companies
United States
Europe
Asia
Total Equity Companies
Total gross and net wells drilling
1,472
1,577
B. Review of Principal Ongoing Activities
UNITED STATES
ExxonMobil’s year-end 2012 acreage holdings totaled 15.6 million net acres, of which 2.2 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.
During 2012, 1,142.7 net exploration and development wells were completed in the inland lower 48 states. Development activities focused on the San Joaquin Basin of California, the Woodford Shale of Oklahoma, the Bakken oil play in North Dakota and Montana, the Permian Basin of West Texas and New Mexico, the Marcellus Shale of Pennsylvania and West Virginia, the Haynesville Shale of Texas and Louisiana, the Barnett Shale of North Texas, the Fayetteville Shale of Arkansas, and the Freestone Trend of East Texas.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2012 was 2.1 million acres. A total of 2.6 net exploration and development wells were completed during the year. Development activities continued on the deepwater Hadrian South project and the non-operated Lucius project.
Participation in Alaska production and development continued with a total of 15.0 net development wells completed. The Point Thomson project was funded by ExxonMobil in 2012.
CANADA / SOUTH AMERICA
Canada
Oil and Gas Operations: ExxonMobil's year-end 2012 acreage holdings totaled 5.2 million net acres, of which 1.5 million net acres were offshore. A total of 44.1 net exploration and development wells were completed during the year. The Hebron project, located offshore Newfoundland, was funded in 2012. ExxonMobil entered into an agreement in 2012 to acquire Celtic Exploration Ltd.
In Situ Bitumen Operations: ExxonMobil's year-end 2012 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 31.0 net development wells were completed during the year. The Cold Lake Nabiye Expansion project was funded in 2012.
Argentina
ExxonMobil’s net acreage totaled 1.0 million onshore acres at year-end 2012, and there was 0.5 net development well completed during the year.
Venezuela
ExxonMobil’s acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of “Note 16: Litigation and Other Contingencies” of the Financial Section of this report for additional information.
EUROPE
Germany
A total of 4.9 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2012, with 6.1 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 2012, of which 1.2 million acres are onshore. A total of 5.7 net exploration and development wells were completed during the year.
Norway
ExxonMobil's net interest in licenses at year-end 2012 totaled approximately 1.0 million acres, all offshore. A total of 6.2 net exploration and development wells were completed in 2012.
United Kingdom
ExxonMobil’s net interest in licenses at year-end 2012 totaled approximately 0.4 million acres, all offshore. A total of 0.9 net development wells were completed during the year. The offshore Fram project was funded in 2012.
AFRICA
Angola
ExxonMobil’s year-end 2012 acreage holdings totaled 0.4 million net offshore acres and 5.4 net exploration and development wells were completed during the year. On Block 15, Kizomba Satellites Phase 1 started up, and Kizomba Satellites Phase 2 was funded in 2012. On the non-operated Block 17, work continued on the Cravo-Lirio-Orquidea-Violeta project. ExxonMobil sold its interest in the non-operated Block 31 in 2012.
Chad
ExxonMobil’s net year-end 2012 acreage holdings consisted of 46 thousand onshore acres, with 26.8 net development wells completed during the year.
Equatorial Guinea
ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2012.
Nigeria
ExxonMobil’s net acreage totaled 0.9 million offshore acres at year-end 2012, with 7.8 net exploration and development wells completed during the year. The Satellite Field Development Phase 1 and the deepwater Usan projects started up in 2012.
ASIA
Azerbaijan
At year-end 2012, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.4 net development wells were completed during the year. Work continued on the Chirag Oil project.
Indonesia
At year-end 2012, ExxonMobil had 5.5 million net acres, 3.4 million net acres offshore and 2.1 million net acres onshore. A total of 2.3 net exploration wells were completed during the year. Project work continued on the full field development at Banyu Urip.
Iraq
At year-end 2012, ExxonMobil’s onshore acreage was 0.9 million net acres. A total of 21.6 net development wells were completed at the West Qurna Phase I oil field during the year. In 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West Qurna Phase I oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities continued during 2012, and across the life of this project will include drilling of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps.
Production sharing contracts were negotiated with the regional government of Kurdistan in 2011, and planning of activities continued during 2012.
Kazakhstan
ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2012. A total of 0.2 net development wells were completed during 2012. Working with our partners, construction of the initial phase of the Kashagan field continued during 2012.
Malaysia
ExxonMobil has interests in production sharing contracts covering 0.4 million net acres offshore at year-end 2012. During the year, a total of 6.9 net exploration and development wells were completed. The Damar project was funded in 2012, and work continued on the Tapis and Telok projects.
Qatar
Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2012. During the year, a total of 1.4 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural 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 2012.
Russia
ExxonMobil’s net acreage holdings at year-end 2012 were 85 thousand acres, all offshore. A total of 0.6 net development wells were completed. Development activities continued on the Arkutun-Dagi project during 2012.
ExxonMobil and Rosneft signed a Strategic Cooperation Agreement in 2011 to jointly participate in exploration and development activities in Russia, the United States and other parts of the world. In 2012 ExxonMobil and Rosneft signed a Pilot Development Agreement to evaluate the development of tight-oil reserves in western Siberia and signed an agreement to establish a joint Arctic Research Center.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2012.
United Arab Emirates
ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2012, with 0.6 net development wells completed during the year.
ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2012, of which 0.4 million acres are onshore. During the year, a total of 5.6 net development wells were completed.
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s year-end 2012 acreage holdings totaled 1.8 million net acres, of which 1.6 million net acres were offshore. During the year, a total of 1.1 net exploration wells were completed.
Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2012. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15.6 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.
Papua New Guinea
A total of 0.9 million net onshore acres were held by ExxonMobil at year-end 2012, with 1.3 net exploration and development wells completed during the year. Work continued on the Papua New Guinea (PNG) LNG project. The project consists of conditioning facilities in the southern PNG Highlands, a 6.9 million tonnes per year LNG facility near Port Moresby and approximately 434 miles of onshore and offshore pipelines.
WORLDWIDE EXPLORATION
At year-end 2012, 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 35.3 million net acres were held at year-end 2012, and 2.1 net 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 3,000 billion cubic feet of natural gas for the period from 2013 through 2015. 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.
7. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
Year-End 2012
Year-End 2011
Oil
Gas
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Gross
Net
Gross and Net Productive Wells
Consolidated Subsidiaries
United States
22,690
8,155
39,720
24,197
23,891
8,219
41,453
24,858
Canada/South America
5,283
4,825
3,485
1,319
5,347
4,870
3,299
1,259
Europe
1,255
1,340
Africa
1,231
1,167
Asia
Australia/Oceania
Total Consolidated Subsidiaries
31,927
14,339
44,082
25,948
33,240
14,481
45,667
26,581
Equity Companies
United States
12,777
5,286
2,138
11,068
5,200
-
Europe
Asia
1,200
Total Equity Companies
14,048
5,442
2,844
12,023
5,323
Total gross and net productive wells
45,975
19,781
46,926
26,282
45,263
19,804
46,382
26,802
There were 37,228 gross and 31,264 net operated wells at year-end 2012 and 37,692 gross and 31,683 net operated wells at year-end 2011. The number of wells with multiple completions was 1,647 gross in 2012 and 1,775 gross in 2011.
B. Gross and Net Developed Acreage
Year-End 2012
Year-End 2011
Gross
Net
Gross
Net
(thousands of acres)
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States
16,444
10,164
17,255
10,256
Canada/South America (1)
4,545
1,940
4,570
1,959
Europe
3,382
1,515
3,563
1,511
Africa
2,105
1,850
Asia
1,322
1,326
Australia/Oceania
2,018
1,955
Total Consolidated Subsidiaries
29,816
15,643
30,519
15,735
Equity Companies
United States
Europe
4,344
1,357
4,343
1,357
Asia
5,731
5,732
Total Equity Companies
10,571
2,199
10,206
2,052
Total gross and net developed acreage
40,387
17,842
40,725
17,787
(1) Includes developed acreage in South America of 618 gross and 202 net thousands of acres for 2012 and 2011.
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 2012
Year-End 2011
Gross
Net
Gross
Net
(thousands of acres)
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States
8,517
5,077
8,718
5,229
Canada/South America (1)
16,669
8,700
19,183
9,877
Europe
35,928
16,123
36,153
16,107
Africa
12,005
7,707
13,242
8,100
Asia
24,346
20,239
23,883
19,914
Australia/Oceania
7,460
1,991
5,892
1,476
Total Consolidated Subsidiaries
104,925
59,837
107,071
60,703
Equity Companies
United States
Europe
-
-
-
-
Asia
Total Equity Companies
Total gross and net undeveloped acreage
105,349
59,950
107,445
60,805
(1) Includes undeveloped acreage in South America of 8,412 gross and 4,484 net thousands of acres for 2012 and 10,922 gross and 5,680 net thousands of acres for 2011.
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.
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 onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed. Argentine provinces are entitled to modify the concession terms granted within their territories. The concession terms of the exploration permits granted by Neuquen Province are up to six years for the initial exploration period, up to four years for the second exploration period and up to three years for the third exploration period depending on the classification of the area. An extension after the third exploration period is possible for up to one year.
EUROPE
Germany
Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years 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.
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 ten 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 plus one or two 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 and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. 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. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated on one calendar year’s notice.
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for 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.
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. 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
Exploration and production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.
In 2008, the Company reached agreement with the national oil company for a new PSC, which was subsequently signed in 2009. Under the new PSC, from 2008 until March 31, 2012, the Company was entitled to undertake new development and production activities in oil fields under an existing PSC, subject to new minimum work and spending commitments, including an enhanced oil recovery project in one of the oil fields. When the existing PSC expired on March 31, 2012, the producing fields covered by the existing PSC automatically became part of the new PSC, which has a 25-year duration from April 2008.
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.
Russia
Terms for ExxonMobil’s 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.
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 are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 2006, for a term expiring March 2026.
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.
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 2012 (1)
ExxonMobil
ExxonMobil
Share KBD (2)
Interest %
United States
Torrance
California
Joliet
Illinois
Baton Rouge
Louisiana
Baytown
Texas
Beaumont
Texas
Other (2 refineries)
Total United States
1,951
Canada
Strathcona
Alberta
69.6
Dartmouth
Nova Scotia
69.6
Nanticoke
Ontario
69.6
Sarnia
Ontario
69.6
Total Canada
Europe
Antwerp
Belgium
Fos-sur-Mer
France
82.9
Gravenchon
France
82.9
Karlsruhe
Germany
Augusta
Italy
Trecate
Italy
75.5
Rotterdam
Netherlands
Slagen
Norway
Fawley
United Kingdom
Total Europe
1,640
Asia Pacific
Jurong/PAC
Singapore
Sriracha
Thailand
Other (7 refineries)
Total Asia Pacific
1,061
Other Non-U.S.
Yanbu
Saudi Arabia
Laffan
Qatar
Martinique
Martinique
14.5
Total Other Non-U.S.
Total Worldwide
5,375
(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 equity interest or that portion of distillation capacity normally available to ExxonMobil.
The marketing operations sell products and services throughout the world through our Exxon, Esso and Mobil brands.
Retail Sites At Year-End 2012
United States
Owned/leased
Distributors/resellers
8,921
Total United States
9,036
Canada
Owned/leased
Distributors/resellers
1,308
Total Canada
1,782
Europe
Owned/leased
3,713
Distributors/resellers
2,361
Total Europe
6,074
Asia Pacific
Owned/leased
Distributors/resellers
Total Asia Pacific
Latin America
Owned/leased
Distributors/resellers
Total Latin America
Middle East/Africa
Owned/leased
Distributors/resellers
Total Middle East/Africa
Worldwide
Owned/leased
5,593
Distributors/resellers
13,789
Total Worldwide
19,382
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 2012 (1)(2)
ExxonMobil
Ethylene
Polyethylene
Polypropylene
Paraxylene
Interest %
North America
Baton Rouge
Louisiana
1.0
1.3
0.4
-
Baytown
Texas
2.2
-
0.8
0.6
Beaumont
Texas
0.9
1.0
-
0.3
Mont Belvieu
Texas
-
1.0
-
-
Sarnia
Ontario
0.3
0.5
-
-
69.6
Total North America
4.4
3.8
1.2
0.9
Europe
Antwerp
Belgium
-
0.4
-
-
Fife
United Kingdom
0.4
-
-
-
Meerhout
Belgium
-
0.5
-
-
Gravenchon
France
0.4
0.4
0.3
-
Rotterdam
Netherlands
-
-
-
0.7
Total Europe
0.8
1.3
0.3
0.7
Middle East
Al Jubail
Saudi Arabia
0.6
0.6
-
-
Yanbu
Saudi Arabia
1.0
0.7
0.2
-
Total Middle East
1.6
1.3
0.2
-
Asia Pacific
Fujian
China
0.2
0.2
0.1
0.2
Kawasaki
Japan
0.1
-
-
-
Singapore
Singapore
0.9
1.9
0.9
0.9
Sriracha
Thailand
-
-
-
0.5
Total Asia Pacific
1.2
2.1
1.0
1.6
All Other
-
-
-
0.2
Total Worldwide
8.0
8.5
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.
Iran Threat Reduction and Syria Human Rights Act of 2012
The captioned Act was signed by President Obama on August 10, 2012. Among other things, the Act extended the prohibition against U.S. persons doing business with the Government of Iran to include such persons’ non-U.S. subsidiaries. Previously, non-U.S. subsidiaries were not covered by this restriction. Application of the restriction to non-U.S. subsidiaries took effect on October 10, 2012. The Act also requires registrants to disclose, in their annual and quarterly reports, activities covered by the Act which occurred anytime during the period covered by the report, even if such activities occurred prior to the effective date of the Act and were permitted at the time.
During the period from January to September, 2012, ExxonMobil’s majority-owned Canadian affiliate, Imperial Oil Limited (IOL), made several fleet sales of motor fuel with an aggregate total sales price of approximately 11,000 Canadian dollars to the Iranian Embassy in Canada. IOL’s net profits attributable to these sales were less than 500 Canadian dollars. The sales were made without the involvement of any U.S. person and were permitted by U.S. laws in effect at the time. No sales occurred after the October 10, 2012, effective date, and we do not expect any such sales to occur in the future.
The embassy sales stated above represent an activity described in paragraph (D)(iii) of paragraph (1) of Section 13(r) of the Securities and Exchange Act of 1934 and therefore are excluded from the required investigation provisions of that statute.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
On October 31, 2012, the Illinois Attorney General and Will County State's Attorney filed a civil complaint and sought a preliminary injunction against ExxonMobil Oil Corporation (EMOC) relating to an October 18, 2012, release of oil mist from a pressure relief valve associated with the coker unit at EMOC’s Joliet Refinery. The refinery reported the incident promptly to regulatory authorities and took prompt response actions. The State’s civil complaint seeks a penalty in excess of $100,000. On November 14, 2012, the parties entered into an Agreed Order resolving some of the issues, including the State’s demand for injunctive relief. As part of the Agreed Order, EMOC agreed to complete an investigation into the incident's cause and to report the findings to the Illinois Environmental Protection Agency (IEPA); submit a work schedule for necessary improvements; report all pollutants and quantities involved in the oil release incident; pay all reasonable response, oversight and review costs relating to the release incurred by the IEPA and the Attorney General, up to and not to exceed $50,000; and reimburse Will County for its reasonable response costs incurred in the course of providing emergency action relating to the release, up to and not to exceed $20,000.
Regarding a matter previously reported in the Corporation’s Form 10-Q for the second quarter of 2012, on December 17, 2012, XTO Energy Inc. (XTO) entered into a settlement agreement and stipulated final compliance order with the New Mexico Environment Department (NMED) arising from NMED’s allegations that XTO violated the New Mexico Air Quality Control Act and air permits for compressor engines at the XTO Valencia Canyon Compressor Station in Rio Arriba County, New Mexico. Under the settlement, XTO has agreed to pay $90,000 to resolve the alleged violations.
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.

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ITEM 4. RESERVED
Item 4. MINE SAFETY DISCLOSURES
Not applicable.
_______________________
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]
(ages as of March 1, 2013).
Rex W. Tillerson
Chairman of the Board
Held current title since:
January 1, 2006
Age: 60
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: 56
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: 59
Mr. Michael J. Dolan was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation September 1, 2004 - March 31, 2008. He 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: 56
Mr. Andrew P. Swiger was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1, 2006 - March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.
S. Jack Balagia
Vice President and General Counsel
Held current title since:
March 1, 2010
Age: 61
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.
William M. Colton
Vice President - Strategic Planning
Held current title since:
February 1, 2009
Age: 59
Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 - January 31, 2009. He became Vice President-Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.
Neil W. Duffin
President, ExxonMobil Development Company
Held current title since:
April 13, 2007
Age: 56
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: 55
Mr. Robert S. Franklin was Executive Assistant to the Chairman, Exxon Mobil Corporation April 16, 2007 - March 31, 2008. He was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008 - May 1, 2009. He became Vice President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures on May 1, 2009, positions he still holds as of this filing date.
Stephen M. Greenlee
Vice President
Held current title since:
September 1, 2010
Age: 55
Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004 - June 1, 2009. He 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.
Alan J. Kelly
Vice President
Held current title since:
December 1, 2007
Age: 55
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 as well as Vice President of Exxon Mobil Corporation, positions he still holds as of this filing date.
Richard M. Kruger
Vice President
Held current title since:
April 1, 2008
Age:
Mr. Richard M. Kruger was Executive Vice President of ExxonMobil Production Company October 1, 2006 - March 31, 2008. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.
Patrick T. Mulva
Vice President and Controller
Held current title since:
February 1, 2002 (Vice President)
July 1, 2004 (Controller)
Age: 61
Mr. Patrick T. Mulva became Vice President and Controller of Exxon Mobil Corporation on July 1, 2004, positions he still holds as of this filing date.
Stephen D. Pryor
Vice President
Held current title since:
December 1, 2004
Age: 63
Mr. Stephen D. Pryor was President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation December 1, 2004 - March 31, 2008. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.
David S. Rosenthal
Vice President - Investor Relations and Secretary
Held current title since:
October 1,
Age: 56
Mr. David S. Rosenthal was Assistant Controller of Exxon Mobil Corporation June 1, 2006 - September 30, 2008. He became Vice President-Investor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still holds as of this filing date.
Robert N. Schleckser
Vice President and Treasurer
Held current title since:
May 1, 2011
Age: 56
Mr. Robert N. Schleckser was Downstream Treasurer, Downstream Business Services May 1, 2005 - January 31, 2009. He 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: 51
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: 58
Mr. Thomas R. Walters was Executive Vice President of ExxonMobil Development Company April 13, 2007 - April 1, 2009. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on April 1, 2009 positions he still holds as of this filing date.
Jack P. Williams, Jr.
President, XTO Energy Inc.
Held current title since:
June 25, 2010
Age:
Mr. Jack P. Williams, Jr. was Vice President, Engineering, ExxonMobil Production Company May 1, 2007 - April 30, 2009. He was Vice President of ExxonMobil Development Company May 1, 2009 - July 1, 2010. He became President of XTO Energy Inc. on June 25, 2010, a position he still holds as of this filing date.
Darren W. Woods
Vice President
Held current title since:
August 1, 2012
Age: 48
Mr. Darren W. Woods was Vice President, Specialty Elastomers Business, ExxonMobil Chemical Company July 1, 2007 -January 31, 2008. He 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 became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on August 1, 2012, 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.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2012
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 2012
18,265,369
91.68
18,265,369
November 2012
20,958,452
88.19
20,958,452
December 2012
19,688,345
87.95
19,688,345
Total
58,912,166
89.19
58,912,166
(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 1, 2013, the Corporation stated that first quarter 2013 share purchases are continuing at a pace consistent with fourth quarter 2012 share reduction spending of $5 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.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
Years Ended December 31,
2012 (1)
(millions of dollars, except per share amounts)
Sales and other operating revenue (2)
453,123
467,029
370,125
301,500
459,579
(2) Sales-based taxes included
32,409
33,503
28,547
25,936
34,508
Net income attributable to ExxonMobil
44,880
41,060
30,460
19,280
45,220
Earnings per common share
9.70
8.43
6.24
3.99
8.70
Earnings per common share - assuming dilution
9.70
8.42
6.22
3.98
8.66
Cash dividends per common share
2.18
1.85
1.74
1.66
1.55
Total assets
333,795
331,052
302,510
233,323
228,052
Long-term debt
7,928
9,322
12,227
7,129
7,025
(1) See Note 20: Japan Restructuring contained in the Financial Section of this report.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 27, 2013, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 20: Japan Restructuring”;
·
“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
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
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, 2012. 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 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, 2012.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2012, 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.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
Effective April 1, 2013, the annual salary for Mark W. Albers will increase to $1,110,000 and Michael J. Dolan will increase to $1,200,000. Like all other ExxonMobil executive officers, Messrs. Albers and Dolan are “at-will” employees of the Corporation and they do not have employment contracts.
PART III

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2013 annual meeting of shareholders (the “2013 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”.

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ITEM 11. EXECUTIVE COMPENSATION
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 2013 Proxy Statement.

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ITEM 12. SECURITY OWNERSHIP
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 2013 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
10,481,088
(1)(2)
-
125,413,149
(2)(3)(4)
Equity compensation plans not approved by security holders
-
-
-
Total
10,481,088
-
125,413,149
(1) The number of restricted stock units to be settled in shares.
(2) Does not include options that ExxonMobil assumed in the 2010 merger with XTO Energy Inc. At year-end 2012, the number of securities to be issued upon exercise of outstanding options under XTO Energy Inc. plans was 2,355,003, and the weighted-average exercise price of such options was $78.60. No additional awards may be made under those plans.
(3) Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 124,736,449 shares available for award under the 2003 Incentive Program and 676,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.
(4) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution 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.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2013 Proxy Statement.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
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 2013 Proxy Statement.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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.
FINANCIAL SECTION
Business Profile
Financial Summary
Frequently Used Terms
Quarterly Information
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
Functional Earnings
Forward-Looking Statements
Overview
Business Environment and Risk Assessment
Review of 2012 and 2011 Results
Liquidity and Capital Resources
Capital and Exploration Expenditures
Taxes
Environmental Matters
Market Risks, Inflation and Other Uncertainties
Critical Accounting Estimates
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Statement of Income
Statement of Comprehensive Income
Balance Sheet
Statement of Cash Flows
Statement of Changes in Equity
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies
2. Accounting Changes
3. Miscellaneous Financial Information
4. Other Comprehensive Income Information
5. Cash Flow Information
6. Additional Working Capital Information
7. Equity Company Information
8. Investments, Advances and Long-Term Receivables
9. Property, Plant and Equipment and Asset Retirement Obligations
10. Accounting for Suspended Exploratory Well Costs
11. Leased Facilities
12. Earnings Per Share
13. Financial Instruments and Derivatives
14. Long-Term Debt
15. Incentive Program
16. Litigation and Other Contingencies
17. Pension and Other Postretirement Benefits
18. Disclosures about Segments and Related Information
19. Income, Sales-Based and Other Taxes
20. Japan Restructuring
Supplemental Information on Oil and Gas Exploration and Production Activities
Operating Summary
BUSINESS PROFILE
Return on
Capital and
Earnings After
Average Capital
Average Capital
Exploration
Income Taxes
Employed
Employed
Expenditures
Financial
(millions of dollars)
(percent)
(millions of dollars)
Upstream
United States
3,925
5,096
57,631
54,994
6.8
9.3
11,080
10,741
Non-U.S.
25,970
29,343
81,811
74,813
31.7
39.2
25,004
22,350
Total
29,895
34,439
139,442
129,807
21.4
26.5
36,084
33,091
Downstream
United States
3,575
2,268
4,630
5,340
77.2
42.5
Non-U.S.
9,615
2,191
19,401
18,048
49.6
12.1
1,628
1,602
Total
13,190
4,459
24,031
23,388
54.9
19.1
2,262
2,120
Chemical
United States
2,220
2,215
4,671
4,791
47.5
46.2
Non-U.S.
1,678
2,168
15,477
15,007
10.8
14.4
1,010
1,160
Total
3,898
4,383
20,148
19,798
19.3
22.1
1,418
1,450
Corporate and financing
(2,103)
(2,221)
(4,527)
(2,272)
-
-
Total
44,880
41,060
179,094
170,721
25.4
24.2
39,799
36,766
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Operating
(thousands of barrels daily)
(thousands of barrels daily)
Net liquids production
Refinery throughput
United States
United States
1,816
1,784
Non-U.S.
1,767
1,889
Non-U.S.
3,198
3,430
Total
2,185
2,312
Total
5,014
5,214
(millions of cubic feet daily)
(thousands of barrels daily)
Natural gas production available for sale
Petroleum product sales
United States
3,822
3,917
United States
2,569
2,530
Non-U.S.
8,500
9,245
Non-U.S.
3,605
3,883
Total
12,322
13,162
Total
6,174
6,413
(thousands of oil-equivalent barrels daily)
(thousands of metric tons)
Oil-equivalent production (1)
4,239
4,506
Chemical prime product sales (2)
United States
9,381
9,250
Non-U.S.
14,776
15,756
Total
24,157
25,006
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Prime product sales include ExxonMobil´s share of equity-company volumes and finished-product transfers to the Downstream.
FINANCIAL SUMMARY
(millions of dollars, except per share amounts)
Sales and other operating revenue (1)
453,123
467,029
370,125
301,500
459,579
Earnings
Upstream
29,895
34,439
24,097
17,107
35,402
Downstream
13,190
4,459
3,567
1,781
8,151
Chemical
3,898
4,383
4,913
2,309
2,957
Corporate and financing
(2,103)
(2,221)
(2,117)
(1,917)
(1,290)
Net income attributable to ExxonMobil
44,880
41,060
30,460
19,280
45,220
Earnings per common share
9.70
8.43
6.24
3.99
8.70
Earnings per common share - assuming dilution
9.70
8.42
6.22
3.98
8.66
Cash dividends per common share
2.18
1.85
1.74
1.66
1.55
Earnings to average ExxonMobil share of equity (percent)
28.0
27.3
23.7
17.3
38.5
Working capital
(4,542)
(3,649)
3,174
23,166
Ratio of current assets to current liabilities (times)
1.01
0.94
0.94
1.06
1.47
Additions to property, plant and equipment
35,179
33,638
74,156
22,491
19,318
Property, plant and equipment, less allowances
226,949
214,664
199,548
139,116
121,346
Total assets
333,795
331,052
302,510
233,323
228,052
Exploration expenses, including dry holes
1,840
2,081
2,144
2,021
1,451
Research and development costs
1,042
1,044
1,012
1,050
Long-term debt
7,928
9,322
12,227
7,129
7,025
Total debt
11,581
17,033
15,014
9,605
9,425
Fixed-charge coverage ratio (times)
62.4
53.4
42.2
25.8
54.6
Debt to capital (percent)
6.3
9.6
9.0
7.7
7.4
Net debt to capital (percent) (2)
1.2
2.6
4.5
(1.0)
(23.0)
ExxonMobil share of equity at year-end
165,863
154,396
146,839
110,569
112,965
ExxonMobil share of equity per common share
36.84
32.61
29.48
23.39
22.70
Weighted average number of common shares
outstanding (millions)
4,628
4,870
4,885
4,832
5,194
Number of regular employees at year-end (thousands) (3)
76.9
82.1
83.6
80.7
79.9
CORS employees not included above (thousands) (4)
11.1
17.0
20.1
22.0
24.8
(1) Sales and other operating revenue includes sales-based taxes of $32,409 million for 2012, $33,503 million for 2011, $28,547 million for 2010, $25,936 million for 2009 and $34,508 million for 2008.
(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.
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
(millions of dollars)
Net cash provided by operating activities
56,170
55,345
48,413
Proceeds associated with sales of subsidiaries, property, plant and equipment,
and sales and returns of investments
7,655
11,133
3,261
Cash flow from operations and asset sales
63,825
66,478
51,674
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
(millions of dollars)
Business uses: asset and liability perspective
Total assets
333,795
331,052
302,510
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable
(60,486)
(69,794)
(59,846)
Total long-term liabilities excluding long-term debt
(90,068)
(83,481)
(74,971)
Noncontrolling interests share of assets and liabilities
(6,235)
(7,314)
(6,532)
Add ExxonMobil share of debt-financed equity company net assets
5,775
4,943
4,875
Total capital employed
182,781
175,406
166,036
Total corporate sources: debt and equity perspective
Notes and loans payable
3,653
7,711
2,787
Long-term debt
7,928
9,322
12,227
ExxonMobil share of equity
165,863
154,396
146,839
Less noncontrolling interests share of total debt
(438)
(966)
(692)
Add ExxonMobil share of equity company debt
5,775
4,943
4,875
Total capital employed
182,781
175,406
166,036
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
(millions of dollars)
Net income attributable to ExxonMobil
44,880
41,060
30,460
Financing costs (after tax)
Gross third-party debt
(401)
(153)
(803)
ExxonMobil share of equity companies
(257)
(219)
(333)
All other financing costs - net
Total financing costs
(558)
(256)
(1,101)
Earnings excluding financing costs
45,438
41,316
31,561
Average capital employed
179,094
170,721
145,217
Return on average capital employed - corporate total
25.4%
24.2%
21.7%
QUARTERLY INFORMATION
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,
2,214
2,208
2,116
2,203
2,185
2,399
2,351
2,249
2,250
2,312
synthetic oil and bitumen
Refinery throughput
5,330
4,962
4,929
4,837
5,014
5,180
5,193
5,232
5,250
5,214
Petroleum product sales
6,316
6,171
6,105
6,108
6,174
6,267
6,331
6,558
6,493
6,413
Natural gas production
(millions of cubic feet daily)
available for sale
14,036
11,661
11,061
12,541
12,322
14,525
12,267
12,197
13,677
13,162
(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)
4,553
4,152
3,960
4,293
4,239
4,820
4,396
4,282
4,530
4,506
(thousands of metric tons)
Chemical prime product sales
6,337
5,972
5,947
5,901
24,157
6,322
6,181
6,232
6,271
25,006
Summarized financial data
Sales and other operating
(millions of dollars)
revenue (2)
119,189
112,745
111,554
109,635
453,123
109,251
121,394
120,475
115,909
467,029
Gross profit (3)
35,672
32,715
33,209
31,969
133,565
35,473
37,744
37,121
34,306
144,644
Net income attributable to
ExxonMobil
9,450
15,910
9,570
9,950
44,880
10,650
10,680
10,330
9,400
41,060
Per share data
(dollars per share)
Earnings per common share (4)
2.00
3.41
2.09
2.20
9.70
2.14
2.19
2.13
1.97
8.43
Earnings per common share
- assuming dilution (4)
2.00
3.41
2.09
2.20
9.70
2.14
2.18
2.13
1.97
8.42
Dividends per common share
0.47
0.57
0.57
0.57
2.18
0.44
0.47
0.47
0.47
1.85
Common stock prices
High
87.94
87.67
92.57
93.67
93.67
88.23
88.13
85.41
85.63
88.23
Low
83.19
77.13
82.83
84.70
77.13
73.64
76.72
67.03
69.21
67.03
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Includes amounts for sales-based taxes.
(3) Gross profit equals sales and other operating revenue less estimated costs associated with products sold.
(4) 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 468,497 registered shareholders of ExxonMobil common stock at December 31, 2012. At January 31, 2013, the registered shareholders of ExxonMobil common stock numbered 466,674.
On January 30, 2013, the Corporation declared a $0.57 dividend per common share, payable March 11, 2013.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS
(millions of dollars, except per share amounts)
Earnings (U.S. GAAP)
Upstream
United States
3,925
5,096
4,272
Non-U.S.
25,970
29,343
19,825
Downstream
United States
3,575
2,268
Non-U.S.
9,615
2,191
2,797
Chemical
United States
2,220
2,215
2,422
Non-U.S.
1,678
2,168
2,491
Corporate and financing
(2,103)
(2,221)
(2,117)
Net income attributable to ExxonMobil
44,880
41,060
30,460
Earnings per common share
9.70
8.43
6.24
Earnings per common share - assuming dilution
9.70
8.42
6.22
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.
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 does not necessarily have the same meaning as under SEC Rule 13q-1 relating to government payment reporting. For example, a single project for purposes of the rule may encompass numerous properties, agreements, investments, developments, phases, work efforts, activities, and components, each of which we may also informally describe as a “project”.
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 tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
By 2040, the world’s population is projected to grow to approximately 8.7 billion people, or about 1.9 billion more than in 2010. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. Expanding prosperity across a growing global population is expected to coincide with an increase in primary energy demand of about 35 percent by 2040 versus 2010, even with substantial efficiency gains around the world. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).
As economic progress for billions of people drives demand higher, increasing penetration of energy-efficient and lower-emission fuels, technologies and practices are expected to contribute to significantly lower levels of energy consumption and emissions per unit of economic output over time. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the penetration of advanced technologies, as well as many other improvements that span the residential, commercial and industrial sectors.
Energy for transportation - including cars, trucks, ships, trains and airplanes - is expected to increase by about 40 percent from 2010 to 2040. The global growth in transportation demand is likely to account for approximately 70 percent of the growth in liquid fuels demand over this period. Nearly all the world’s transportation fleets will continue to run on liquid fuels because they provide a large quantity of energy in small volumes, making them easy to transport and widely available.
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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 wind, are expected to grow significantly over the period.
Liquid fuels provide the largest share of energy supply today due to their broad-based availability, affordability and ease of transport to meet consumer needs. By 2040, global demand for liquids is expected to grow to approximately 113 million barrels of oil-equivalent per day, an increase of about 30 percent from 2010. Global demand for liquid fuels will be met by a wide variety of sources. Conventional crude and condensate production is expected to remain relatively flat through 2040. However, growth is expected from a wide variety of sources, including deep-water resources, oil sands, tight oil, 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 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 demand increases in major regions around the world requiring new sources of supply. 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. By 2040, unconventional gas is likely to approach one-third of global gas supplies, up from less than 15 percent in 2010. Growing natural gas demand will also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, which is expected to reach about 15 percent of global gas demand by 2040.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share 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 by approximately 2025. 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, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsunami in March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, including biomass, hydro and geothermal at a combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 450 percent from 2010 to 2040, reaching a combined share of 3 to 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 2012-2035 will be close to $19 trillion (measured in 2011 dollars) or close to $800 billion per year on average.
International accords and underlying regional and national regulations for greenhouse gas reduction 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 Energy Outlook, which is used 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 identifying and selectively capturing the highest quality opportunities, exercising a disciplined approach to investing and cost management, developing and applying high-impact technologies, maximizing the profitability of existing 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 of its production volumes between now and 2017. Oil and natural gas output from North America is expected to increase over the next five years based on current capital activity plans. Currently, this growth area accounts for 32 percent of the Corporation’s production. By 2017, it is expected to generate about 35 percent of total volumes. The remainder of the Corporation’s production is expected to include contributions from both established operations and new projects around the globe.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
In addition to an evolving geographic mix, we expect there will also be continued change in the type of opportunities from which volumes are produced. Production from diverse resource types utilizing specialized technologies such as arctic technology, deepwater drilling and production systems, heavy oil and oil sands recovery processes, unconventional gas and oil production and LNG is expected to grow from about 45 percent to around 55 percent of the Corporation’s output between now and 2017. We do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a material impact on the nature and the extent of the risks disclosed in Item 1A. Risk Factors, or result in a material change in our level of unit operating expenses. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2013-2017. 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, asset sales, weather events, price effects under 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.
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 maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers.
ExxonMobil has an ownership interest in 32 refineries, located in 17 countries, with distillation capacity of 5.4 million barrels per day and lubricant basestock manufacturing capacity of 126 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 put pressure on margins. In the near term, we see variability in refining margins, with some regions seeing stronger margins as refineries rationalize. In markets like North America, lower raw material and energy costs driven by the increasing crude and natural gas production strengthened refining margins in several areas.
Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for 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, refinery operations, import/export balances, currency fluctuations, seasonal demand, weather and political climate.
ExxonMobil’s long-term outlook is that refining margins will remain weak as competition in the industry remains intense and, 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.
In the retail fuels marketing business, competition continues to cause inflation-adjusted margins to decline. In 2012, ExxonMobil progressed the transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a more capital-efficient branded distributor model. This transition was announced in 2008 and is nearing completion.
Our lubricants business continues to grow. ExxonMobil is a market leader in high-value synthetic lubricants, and we continue to grow our business in key markets such as China, India and Russia at rates considerably faster than industry.
The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. In 2012, we divested our Downstream businesses in Argentina, Uruguay, Paraguay, Central America, Malaysia, and Switzerland. We also restructured and reduced our holdings in Japan. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. These investments capitalize on the Corporation’s world-class scale and integration, industry leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging growth opportunities around the globe. In 2012, the company completed the Hydrofiner Conversion Project at the Fawley, United Kingdom, refinery to produce higher-value ultra-low sulfur diesel.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
At the Jurong/PAC refinery in Singapore, construction activities to build a new diesel hydrotreater are expected to complete in 2013, adding capacity of more than 2 million gallons per day of ultra-low sulfur diesel to meet increasing demand in the Asia Pacific region. Additionally, construction of a lower sulfur fuels project at the joint Saudi Aramco and ExxonMobil SAMREF Refinery in Yanbu, Saudi Arabia is also underway. The project will include new gasoline and expanded diesel hydrotreating and sulfur recovery equipment, and completion is expected by the end of 2013. We are also expanding our Singapore and China lube oil blending plants to support future demand growth in these emerging markets.
Chemical
Worldwide petrochemical demand grew modestly in 2012 with substantial variations in regional performance. In North America, unconventional natural gas continued to provide advantaged ethane feedstock and low cost energy for steam crackers and a favorable margin environment for integrated chemical producers. Margins in Asia remained low, with excess ethylene supply. Margins and volumes declined in Europe with the weaker economy. Specialty products overall reported firm global demand and margins.
ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of commodity petrochemical products, ExxonMobil Chemical also has a number of less-cyclical Specialties business lines, which delivered strong results in 2012. Chemical’s competitive advantages are due to its business mix, broad geographic coverage, investment and cost discipline, integration with refineries or upstream gas processing facilities, superior feedstock management, leading proprietary technology and product application expertise.
In 2012 ExxonMobil completed construction of the Singapore petrochemical expansion project and commenced start-up operations at one of the world’s largest ethylene steam crackers, the centerpiece of the company’s multi-billion dollar expansion at the complex. Powered by a new 220-megawatt cogeneration plant, the expansion adds 2.6 million tonnes per year of new finished product capacity.
REVIEW OF 2012 AND 2011 RESULTS
(millions of dollars)
Earnings (U.S. GAAP)
44,880
41,060
30,460
Earnings in 2012 of $44,880 million increased $3,820 million from 2011.
Earnings in 2011 of $41,060 million increased $10,600 million from 2010.
Upstream
(millions of dollars)
Upstream
United States
3,925
5,096
4,272
Non-U.S.
25,970
29,343
19,825
Total
29,895
34,439
24,097
Upstream earnings were $29,895 million, down $4,544 million from 2011. Lower liquids realizations, partly offset by improved natural gas realizations, decreased earnings by about $100 million. Production volume and mix effects decreased earnings by $2.3 billion. All other items, including higher operating expenses, unfavorable tax items, lower gains on asset sales, and unfavorable foreign exchange effects, reduced earnings by $2.1 billion. On an oil-equivalent basis, production was down 5.9 percent compared to 2011. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was down 1.7 percent. Liquids production of 2,185 kbd (thousands of barrels per day) decreased 127 kbd from 2011. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was down 1.6 percent, as field decline was partly offset by project ramp-up in West Africa and lower downtime. Natural gas production of 12,322 mcfd (millions of cubic feet per day) decreased 840 mcfd from 2011. Excluding the impacts of entitlement volumes and divestments, natural gas production was down 1.9 percent, as field decline was partially offset by higher demand and lower downtime. Earnings from
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
U.S. Upstream operations for 2012 were $3,925 million, down $1,171 million from 2011. Earnings outside the U.S. were $25,970 million, down $3,373 million.
Upstream earnings were $34,439 million, up $10,342 million from 2010. Higher crude oil and natural gas realizations increased earnings by $10.6 billion, while volume and production mix effects decreased earnings by $2.5 billion. All other items increased earnings by $2.2 billion, driven by higher gains on asset sales of $2.7 billion, partly offset by increased operating activity. On an oil-equivalent basis, production was up 1 percent compared to 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 4 percent. Liquids production of 2,312 kbd decreased 110 kbd from 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was in line with 2010, as higher volumes from Qatar, the U.S., and Iraq offset field decline. Natural gas production of 13,162 mcfd increased 1,014 mcfd from 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar. Earnings from U.S. Upstream operations for 2011 were $5,096 million, an increase of $824 million. Earnings outside the U.S. were $29,343 million, up $9,518 million.
Downstream
(millions of dollars)
Downstream
United States
3,575
2,268
Non-U.S.
9,615
2,191
2,797
Total
13,190
4,459
3,567
Downstream earnings of $13,190 million increased $8,731 million from 2011. Stronger refining-driven margins increased earnings by $2.6 billion, while volume and mix effects increased earnings by about $200 million. All other items increased earnings by $5.9 billion due primarily to the $5.3 billion gain associated with the Japan restructuring and other divestment gains. Petroleum product sales of 6,174 kbd decreased 239 kbd from 2011 due mainly to the Japan restructuring and divestments. U.S. Downstream earnings were $3,575 million, up $1,307 million from 2011. Non-U.S. Downstream earnings were $9,615 million, an increase of $7,424 million from last year.
Downstream earnings of $4,459 million increased $892 million from 2010. Margins, mainly refining, increased earnings by $800 million. Volume and mix effects improved earnings by $630 million. All other items, primarily the absence of favorable tax effects and higher expenses, decreased earnings by $540 million. Petroleum product sales of 6,413 kbd were in line with 2010. U.S. Downstream earnings were $2,268 million, up $1,498 million from 2010. Non-U.S. Downstream earnings were $2,191 million, $606 million lower than 2010.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Chemical
(millions of dollars)
Chemical
United States
2,220
2,215
2,422
Non-U.S.
1,678
2,168
2,491
Total
3,898
4,383
4,913
Chemical earnings of $3,898 million were $485 million lower than 2011. Margins decreased earnings by $440 million, while volume effects lowered earnings by $100 million. All other items increased earnings by $50 million, as a $630 million gain associated with the Japan restructuring and favorable tax impacts were mostly offset by unfavorable foreign exchange effects and higher operating expenses. Prime product sales of 24,157 kt (thousands of metric tons) were down 849 kt from 2011. U.S. Chemical earnings were $2,220 million, up $5 million from 2011. Non-U.S. Chemical earnings were $1,678 million, $490 million lower than last year.
Chemical earnings of $4,383 million were down $530 million from 2010. Stronger margins increased earnings by $260 million, while lower volumes reduced earnings by $180 million. Other items, including unfavorable tax effects and higher planned maintenance expense, decreased earnings by $610 million. Prime product sales of 25,006 kt were down 885 kt from 2010. U.S. Chemical earnings were $2,215 million, down $207 million from 2010. Non-U.S. Chemical earnings were $2,168 million, $323 million lower than 2010.
Corporate and Financing
(millions of dollars)
Corporate and financing
(2,103)
(2,221)
(2,117)
Corporate and financing expenses were $2,103 million, down $118 million from 2011.
Corporate and financing expenses were $2,221 million, up $104 million from 2010.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
(millions of dollars)
Net cash provided by/(used in)
Operating activities
56,170
55,345
48,413
Investing activities
(25,601)
(22,165)
(24,204)
Financing activities
(33,868)
(28,256)
(26,924)
Effect of exchange rate changes
(85)
(153)
Increase/(decrease) in cash and cash equivalents
(3,082)
4,839
(2,868)
(December 31)
Cash and cash equivalents
9,582
12,664
7,825
Cash and cash equivalents - restricted
Total cash and cash equivalents
9,923
13,068
8,453
Total cash and cash equivalents were $9.9 billion at the end of 2012, $3.1 billion lower than the prior year. Higher earnings and a higher adjustment for non-cash transactions were more than offset by lower proceeds from sales of subsidiaries and property, plant and equipment, a net debt decrease compared to a prior year debt increase, and a higher adjustment for net gains on asset sales. Included in total cash and cash equivalents at year-end 2012 was $0.3 billion of restricted cash.
Total cash and cash equivalents were $13.1 billion at the end of 2011, $4.6 billion higher than the prior year. Higher earnings, proceeds associated with asset sales, including a $3.6 billion deposit for a potential asset sale, and a net debt increase in contrast with prior year debt repurchases were partially offset by a higher level of purchases of ExxonMobil shares and a higher level of capital spending. Included in total cash and cash equivalents at year-end 2011 was $0.4 billion of restricted cash. For additional details, see the Consolidated Statement of Cash Flows.
Although the Corporation has access to significant capacity of long-term and short-term liquidity, internally generated funds cover the majority of its financial requirements. 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 contractual 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, 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 2012 were $39.8 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment profile of about $38 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Cash Flow from Operating Activities
Cash provided by operating activities totaled $56.2 billion in 2012, $0.8 billion higher than 2011. The major source of funds was net income including noncontrolling interests of $47.7 billion, an increase of $5.5 billion. The noncash provision of $15.9 billion for depreciation and depletion was slightly higher than 2011. The adjustments for other noncash transactions and changes in operational working capital, excluding cash and debt, both increased cash in 2012, while the adjustment for net gains on asset sales decreased cash by $13.0 billion in 2012.
Cash provided by operating activities totaled $55.3 billion in 2011, $6.9 billion higher than 2010. The major source of funds was net income including noncontrolling interests of $42.2 billion, adjusted for the noncash provision of $15.6 billion for depreciation and depletion, both of which increased. Changes in operational working capital, excluding cash and debt, and the adjustment for net gains on asset sales decreased cash in 2011. Net working capital continued to be negative as total current liabilities of $77.5 billion exceeded total current assets of $73.0 billion at year-end 2011.
Cash Flow from Investing Activities
Cash used in investment activities netted to $25.6 billion in 2012, $3.4 billion higher than 2011. Spending for property, plant and equipment of $34.3 billion increased $3.3 billion from 2011. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $7.7 billion compared to $11.1 billion in 2011. The decrease reflects that a $3.6 billion deposit was received in 2011 for a sale that closed in 2012. Additional investments and advances were $2.6 billion lower in 2012.
Cash used in investment activities netted to $22.2 billion in 2011, $2.0 billion lower than 2010. Spending for property, plant and equipment of $31.0 billion increased $4.1 billion from 2010. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $11.1 billion compared to $3.3 billion in 2010. The increase primarily reflects the sale of Upstream Canadian, U.K. and other producing properties and assets, the sale of U.S. service stations, and a $3.6 billion deposit for a potential asset sale. Additional investments and advances were $2.3 billion higher in 2011.
Cash Flow from Financing Activities
Cash used in financing activities was $33.9 billion in 2012, $5.6 billion higher than 2011. Dividend payments on common shares increased to $2.18 per share from $1.85 per share and totaled $10.1 billion, a pay-out of 22 percent of net income. Total debt decreased $5.5 billion to $11.6 billion at year-end.
ExxonMobil share of equity increased $11.5 billion to $165.9 billion. The addition to equity for earnings of $44.9 billion was partially offset by reductions for distributions to ExxonMobil shareholders of $10.1 billion of dividends and $20.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding.
During 2012, Exxon Mobil Corporation purchased 244 million shares of its common stock for the treasury at a gross cost of $21.1 billion. 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 4.9 percent from 4,734 million to 4,502 million at the end of 2012. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.
Cash used in financing activities was $28.3 billion in 2011, $1.3 billion higher than 2010. Dividend payments on common shares increased to $1.85 per share from $1.74 per share and totaled $9.0 billion, a pay-out of 22 percent of net income. Total debt increased $2.0 billion to $17.0 billion at year-end.
ExxonMobil share of equity increased $7.6 billion to $154.4 billion. The addition to equity for earnings of $41.1 billion was partially offset by reductions for distributions to ExxonMobil shareholders of $9.0 billion of dividends and $20.0 billion of
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
purchases of shares of ExxonMobil stock to reduce shares outstanding. The change in the funded status of the postretirement benefits reserves in 2011 decreased equity by $4.6 billion.
During 2011, Exxon Mobil Corporation purchased 278 million shares of its common stock for the treasury at a gross cost of $22.1 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 4.9 percent from 4,979 million to 4,734 million at the end of 2011. Purchases were made in both the open market and through negotiated transactions.
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, 2012. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.
Payments Due by Period
Note
Reference
and
Commitments
Number
Beyond
Total
(millions of dollars)
Long-term debt (1)
-
2,885
5,043
7,928
- Due in one year (2)
1,025
-
-
1,025
Asset retirement obligations (3)
3,334
7,863
11,973
Pension and other postretirement obligations (4)
2,401
4,328
19,475
26,204
Operating leases (5)
2,254
4,460
1,467
8,181
Unconditional purchase obligations (6)
1,127
Take-or-pay obligations (7)
2,673
10,523
13,013
26,209
Firm capital commitments (8)
19,609
12,074
32,519
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 $7.7 billion as of December 31, 2012, 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 $431 million.
(2) The amount due in one year is included in notes and loans payable of $3,653 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 2013 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 $1,127 million mainly pertain to pipeline throughput agreements and include $584 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 $26,209 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $187 million of obligations to equity companies.
(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $32.5 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $18.4 billion was associated with projects in Canada, Australia, Africa and Malaysia. The Corporation expects to fund the majority of these projects through internal cash flow.
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, 2012, 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, 2012, unused credit lines for short-term financing totaled approximately $3.5 billion (Note 6).
The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness.
Fixed-charge coverage ratio (times)
62.4
53.4
42.2
Debt to capital (percent)
6.3
9.6
9.0
Net debt to capital (percent)
1.2
2.6
4.5
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CAPITAL AND EXPLORATION EXPENDITURES
U.S.
Non-U.S.
Total
U.S.
Non-U.S.
Total
(millions of dollars)
Upstream (1)
11,080
25,004
36,084
10,741
22,350
33,091
Downstream
1,628
2,262
1,602
2,120
Chemical
1,010
1,418
1,160
1,450
Other
-
-
Total
12,157
27,642
39,799
11,654
25,112
36,766
(1) Exploration expenses included.
Capital and exploration expenditures in 2012 were $39.8 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation anticipates an investment profile of about $38 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects and property acquisitions.
Upstream spending of $36.1 billion in 2012 was up 9 percent from 2011, reflecting investments in the Gulf of Mexico and continued progress on world-class projects in Canada, Australia and Papua New Guinea. Property acquisition costs in 2012 were comparable to 2011. 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 from those reserves. The percentage of proved developed reserves was 61 percent of total proved reserves at year-end 2012, and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.3 billion in 2012, an increase of $0.1 billion from 2011, mainly reflecting higher environmental and energy-related refining project spending. The Chemical capital expenditures of $1.4 billion were the same level as in 2011 with higher investments in the U.S., Saudi Arabia and China offsetting reduced spending on the Singapore expansion as it approaches full start-up.
TAXES
(millions of dollars)
Income taxes
31,045
31,051
21,561
Effective income tax rate
44%
46%
45%
Sales-based taxes
32,409
33,503
28,547
All other taxes and duties
38,857
43,544
39,127
Total
102,311
108,098
89,235
Income, sales-based and all other taxes and duties totaled $102.3 billion in 2012, a decrease of $5.8 billion or 5 percent from 2011. Income tax expense, both current and deferred, was $31.0 billion, flat with 2011, with the impact of higher earnings offset by the lower effective tax rate. The effective tax rate was 44 percent compared to 46 percent in the prior year due to a lower effective tax rate on divestments. Sales-based and all other taxes and duties of $71.3 billion in 2012 decreased $5.8 billion reflecting the Japan restructuring.
Income, sales based and all other taxes and duties totaled $108.1 billion in 2011, an increase of $18.9 billion or 21 percent from 2010. Income tax expense, both current and deferred, was $31.1 billion, $9.5 billion higher than 2010, reflecting higher pre-tax income in 2011. A higher share of pre-tax income from the Upstream segment in 2011 increased the effective tax rate to 46 percent compared to 45 percent in 2010. Sales-based and all other taxes and duties of $77.0 billion in 2011 increased $9.4 billion, reflecting higher prices.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ENVIRONMENTAL MATTERS
Environmental Expenditures
(millions of dollars)
Capital expenditures
1,989
1,636
Other expenditures
3,523
3,248
Total
5,512
4,884
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 2012 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.5 billion. The total cost for such activities is expected to have a modest increase in 2013 and 2014 (with capital expenditures approximately 45 percent of the total).
Environmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. 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 2012 for environmental liabilities were $391 million ($420 million in 2011) and the balance sheet reflects accumulated liabilities of $841 million as of December 31, 2012, and $886 million as of December 31, 2011.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations (1)
Crude oil and NGL ($/barrel)
100.29
100.79
74.04
Natural gas ($/kcf)
3.90
4.65
4.31
(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 $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide 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.
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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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 are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests 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 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. Although the Corporation issues long-term debt from time to time and maintains a commercial paper program, internally generated funds are expected to cover the majority of its net near-term financial requirements. However, 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 counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and 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 integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating 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 61 percent of total proved reserves at year-end 2012 (including both consolidated and equity company reserves), and has been over 60 percent for the last five 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 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 developed 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-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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the 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 as of year-end 2012 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 and liabilities. Amounts representing the Corporation’s interest in the underlying net assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.
Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks, and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its share of all assets and liabilities in these partially owned companies rather than only its interest in net equity. This method of accounting for investments in partially-owned companies is not permitted by U.S. GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by U.S. GAAP standards, the Corporation includes its share of debt of these partially-owned companies in the determination of average capital employed.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Pension Benefits
The Corporation and its affiliates sponsor over 100 defined benefit (pension) plans in about 50 countries. Pension and Other Postretirement Benefits (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 2012 was 7.25 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were both 9 percent. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $150 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount 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.
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 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, 2012.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2012, as stated in their report included in the Financial Section of this report.
Rex W. Tillerson
Chief Executive Officer
Andrew P. Swiger
Senior Vice President
(Principal Financial Officer)
Patrick T. Mulva
Vice President and Controller
(Principal Accounting Officer)
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, 2012, and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control - Integrated Framework 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 27, 2013
CONSOLIDATED STATEMENT OF INCOME
Note
Reference
Number
(millions of dollars)
Revenues and other income
Sales and other operating revenue (1)
453,123
467,029
370,125
Income from equity affiliates
15,010
15,289
10,677
Other income
14,162
4,111
2,419
Total revenues and other income
482,295
486,429
383,221
Costs and other deductions
Crude oil and product purchases
265,149
266,534
197,959
Production and manufacturing expenses
38,521
40,268
35,792
Selling, general and administrative expenses
13,877
14,983
14,683
Depreciation and depletion
15,888
15,583
14,760
Exploration expenses, including dry holes
1,840
2,081
2,144
Interest expense
Sales-based taxes (1)
32,409
33,503
28,547
Other taxes and duties
35,558
39,973
36,118
Total costs and other deductions
403,569
413,172
330,262
Income before income taxes
78,726
73,257
52,959
Income taxes
31,045
31,051
21,561
Net income including noncontrolling interests
47,681
42,206
31,398
Net income attributable to noncontrolling interests
2,801
1,146
Net income attributable to ExxonMobil
44,880
41,060
30,460
Earnings per common share (dollars)
9.70
8.43
6.24
Earnings per common share - assuming dilution (dollars)
9.70
8.42
6.22
(1) Sales and other operating revenue includes sales-based taxes of $32,409 million for 2012, $33,503 million for 2011 and $28,547 million for 2010.
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(millions of dollars)
Net income including noncontrolling interests
47,681
42,206
31,398
Other comprehensive income (net of income taxes)
Foreign exchange translation adjustment
(867)
1,034
Adjustment for foreign exchange translation (gain)/loss
included in net income
(4,352)
-
Postretirement benefits reserves adjustment (excluding amortization)
(3,574)
(4,907)
(1,161)
Amortization and settlement of postretirement benefits reserves
adjustment included in net periodic benefit costs
2,395
1,217
1,040
Change in fair value of cash flow hedges
-
Realized (gain)/loss from settled cash flow hedges included in net income
-
(83)
(129)
Total other comprehensive income
(4,611)
(4,612)
Comprehensive income including noncontrolling interests
43,070
37,594
32,391
Comprehensive income attributable to noncontrolling interests
1,251
1,293
Comprehensive income attributable to ExxonMobil
41,819
36,760
31,098
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED BALANCE SHEET
Note
Reference
Dec. 31
Dec. 31
Number
(millions of dollars)
Assets
Current assets
Cash and cash equivalents
9,582
12,664
Cash and cash equivalents - restricted
Notes and accounts receivable, less estimated doubtful amounts
34,987
38,642
Inventories
Crude oil, products and merchandise
10,836
11,665
Materials and supplies
3,706
3,359
Other current assets
5,008
6,229
Total current assets
64,460
72,963
Investments, advances and long-term receivables
34,718
34,333
Property, plant and equipment, at cost, less accumulated depreciation
and depletion
226,949
214,664
Other assets, including intangibles, net
7,668
9,092
Total assets
333,795
331,052
Liabilities
Current liabilities
Notes and loans payable
3,653
7,711
Accounts payable and accrued liabilities
50,728
57,067
Income taxes payable
9,758
12,727
Total current liabilities
64,139
77,505
Long-term debt
7,928
9,322
Postretirement benefits reserves
25,267
24,994
Deferred income tax liabilities
37,570
36,618
Long-term obligations to equity companies
3,555
1,808
Other long-term obligations
23,676
20,061
Total liabilities
162,135
170,308
Commitments and contingencies
Equity
Common stock without par value
(9,000 million shares authorized, 8,019 million shares issued)
9,653
9,512
Earnings reinvested
365,727
330,939
Accumulated other comprehensive income
(12,184)
(9,123)
Common stock held in treasury
(3,517 million shares in 2012 and 3,285 million shares in 2011)
(197,333)
(176,932)
ExxonMobil share of equity
165,863
154,396
Noncontrolling interests
5,797
6,348
Total equity
171,660
160,744
Total liabilities and equity
333,795
331,052
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
Note
Reference
Number
(millions of dollars)
Cash flows from operating activities
Net income including noncontrolling interests
47,681
42,206
31,398
Adjustments for noncash transactions
Depreciation and depletion
15,888
15,583
14,760
Deferred income tax charges/(credits)
3,142
(1,135)
Postretirement benefits expense
in excess of/(less than) net payments
(315)
1,700
Other long-term obligation provisions
in excess of/(less than) payments
1,643
(151)
Dividends received greater than/(less than) equity in current
earnings of equity companies
(1,157)
(273)
(596)
Changes in operational working capital, excluding cash and debt
Reduction/(increase)
- Notes and accounts receivable
(1,082)
(7,906)
(5,863)
- Inventories
(1,873)
(2,208)
(1,148)
- Other current assets
(42)
Increase/(reduction)
- Accounts and other payables
3,624
8,880
9,943
Net (gain) on asset sales
(13,018)
(2,842)
(1,401)
All other items - net
1,679
1,148
(318)
Net cash provided by operating activities
56,170
55,345
48,413
Cash flows from investing activities
Additions to property, plant and equipment
(34,271)
(30,975)
(26,871)
Proceeds associated with sales of subsidiaries, property, plant
and equipment, and sales and returns of investments
7,655
11,133
3,261
Decrease/(increase) in restricted cash and cash equivalents
(628)
Additional investments and advances
(972)
(3,586)
(1,239)
Collection of advances
1,924
1,119
1,133
Additions to marketable securities
-
(1,754)
(15)
Sales of marketable securities
-
1,674
Net cash used in investing activities
(25,601)
(22,165)
(24,204)
Cash flows from financing activities
Additions to long-term debt
1,143
Reductions in long-term debt
(147)
(266)
(6,224)
Additions to short-term debt
1,063
Reductions in short-term debt
(4,488)
(1,103)
(2,436)
Additions/(reductions) in debt with three months or less maturity
(226)
1,561
Cash dividends to ExxonMobil shareholders
(10,092)
(9,020)
(8,498)
Cash dividends to noncontrolling interests
(327)
(306)
(281)
Changes in noncontrolling interests
(16)
(7)
Tax benefits related to stock-based awards
Common stock acquired
(21,068)
(22,055)
(13,093)
Common stock sold
1,043
Net cash used in financing activities
(33,868)
(28,256)
(26,924)
Effects of exchange rate changes on cash
(85)
(153)
Increase/(decrease) in cash and cash equivalents
(3,082)
4,839
(2,868)
Cash and cash equivalents at beginning of year
12,664
7,825
10,693
Cash and cash equivalents at end of year
9,582
12,664
7,825
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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, 2009
5,503
276,937
(5,461)
(166,410)
110,569
4,823
115,392
Amortization of stock-based awards
-
-
-
-
Tax benefits related to stock-based awards
-
-
-
-
Other
(683)
-
-
-
(683)
(673)
Net income for the year
-
30,460
-
-
30,460
31,398
Dividends - common shares
-
(8,498)
-
-
(8,498)
(281)
(8,779)
Other comprehensive income
-
-
-
Acquisitions, at cost
-
-
-
(13,093)
(13,093)
(5)
(13,098)
Issued for XTO merger
3,520
-
-
21,139
24,659
-
24,659
Other dispositions
-
-
-
1,756
1,756
-
1,756
Balance as of December 31, 2010
9,371
298,899
(4,823)
(156,608)
146,839
5,840
152,679
Amortization of stock-based awards
-
-
-
-
Tax benefits related to stock-based awards
-
-
-
-
Other
(803)
-
-
-
(803)
(5)
(808)
Net income for the year
-
41,060
-
-
41,060
1,146
42,206
Dividends - common shares
-
(9,020)
-
-
(9,020)
(306)
(9,326)
Other comprehensive income
-
-
(4,300)
-
(4,300)
(312)
(4,612)
Acquisitions, at cost
-
-
-
(22,055)
(22,055)
(15)
(22,070)
Dispositions
-
-
-
1,731
1,731
-
1,731
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
-
-
-
-
Tax benefits related to stock-based awards
-
-
-
-
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
-
-
-
-
Balance as of December 31, 2012
9,653
365,727
(12,184)
(197,333)
165,863
5,797
171,660
Held in
Common Stock Share Activity
Issued
Treasury
Outstanding
(millions of shares)
Balance as of December 31, 2009
8,019
(3,292)
4,727
Acquisitions
-
(199)
(199)
Issued for XTO merger
-
Other dispositions
-
Balance as of December 31, 2010
8,019
(3,040)
4,979
Acquisitions
-
(278)
(278)
Dispositions
-
Balance as of December 31, 2011
8,019
(3,285)
4,734
Acquisitions
-
(244)
(244)
Dispositions
-
Balance as of December 31, 2012
8,019
(3,517)
4,502
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream).
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2012 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 and liabilities.
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, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. 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
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.
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.
The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a 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.
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 costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices, refining and chemical margins and foreign currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.
Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable 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.
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 market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See Note 15, Incentive Program, for further details.
2. Accounting Changes
The Corporation did not adopt authoritative guidance in 2012 that had a material impact on the Corporation’s financial statements.
3. Miscellaneous Financial Information
Research and development expenses totaled $1,042 million in 2012, $1,044 million in 2011 and $1,012 million in 2010.
Net income included before-tax aggregate foreign exchange transaction gains of $159 million, and losses of $184 million and $251 million in 2012, 2011 and 2010, respectively.
In 2012, 2011 and 2010, net income included gains of $328 million, $292 million and $317 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 $21.3 billion and $25.6 billion at December 31, 2012, and 2011, respectively.
Crude oil, products and merchandise as of year-end 2012 and 2011 consist of the following:
(billions of dollars)
Petroleum products
3.6
4.1
Crude oil
4.0
4.8
Chemical products
2.9
2.3
Gas/other
0.3
0.5
Total
10.8
11.7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Other Comprehensive Income Information
Cumulative
Post-
Unrealized
Foreign
retirement
Change in
Exchange
Benefits
Fair Value
ExxonMobil Share of Accumulated Other
Translation
Reserves
on Cash
Comprehensive Income
Adjustment
Adjustment
Flow Hedges
Total
(millions of dollars)
Balance as of December 31, 2009
4,402
(9,863)
-
(5,461)
Current period change excluding amounts reclassified
from accumulated other comprehensive income
(1,014)
(246)
Amounts reclassified from accumulated other
comprehensive income
(129)
Total change in accumulated other comprehensive income
(26)
Balance as of December 31, 2010
5,011
(9,889)
(4,823)
Balance as of December 31, 2010
5,011
(9,889)
(4,823)
Current period change excluding amounts reclassified
from accumulated other comprehensive income
(843)
(4,557)
(5,372)
Amounts reclassified from accumulated other
comprehensive income
-
1,155
(83)
1,072
Total change in accumulated other comprehensive income
(843)
(3,402)
(55)
(4,300)
Balance as of December 31, 2011
4,168
(13,291)
-
(9,123)
Balance as of December 31, 2011
4,168
(13,291)
-
(9,123)
Current period change excluding amounts reclassified
from accumulated other comprehensive income
(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)
Income Tax (Expense)/Credit For
Components of Other Comprehensive Income
(millions of dollars)
Foreign exchange translation adjustment
(236)
(42)
Postretirement benefits reserves adjustment
Postretirement benefits reserves adjustment (excluding amortization)
1,619
2,039
Amortization and settlement of postretirement benefits reserves
adjustment included in net periodic benefit costs
(1,226)
(544)
(654)
Unrealized change in fair value on cash flow hedges
Change in fair value of cash flow hedges
-
(16)
(113)
Settled cash flow hedges included in net income
-
Total
1,618
(41)
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.
The “Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains from 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 the Downstream affiliates in Malaysia and Switzerland in 2012; from the sale of some Upstream Canadian, U.K. and other producing properties and assets, and the sale of U.S. service stations in 2011; and from the sale of some Upstream Gulf of Mexico and other producing properties, the sale of U.S. service stations and other Downstream assets and investments and the formation of a Chemical joint venture in 2010. These gains are reported in “Other income” on the Consolidated Statement of Income.
In 2012, the Corporation’s interest in a cost company was redeemed. As part of the redemption, a variable note due in 2035 issued by Mobil 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.
In 2011, included in “Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments” is a $3.6 billion deposit for an asset that was sold in 2012.
In 2010, the Corporation acquired all the outstanding equity of XTO Energy Inc. in an all-stock transaction valued at $24,659 million.
(millions of dollars)
Cash payments for interest
Cash payments for income taxes
24,349
27,254
18,941
6. Additional Working Capital Information
Dec. 31
Dec. 31
(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $109 million and $128 million
28,373
30,044
Other, less reserves of $36 million and $39 million
6,614
8,598
Total
34,987
38,642
Notes and loans payable
Bank loans
1,237
Commercial paper
1,963
2,281
Long-term debt due within one year
1,025
3,431
Other
Total
3,653
7,711
Accounts payable and accrued liabilities
Trade payables
33,789
33,969
Payables to equity companies
6,114
5,553
Accrued taxes other than income taxes
4,130
7,123
Other
6,695
10,422
Total
50,728
57,067
On December 31, 2012, unused credit lines for short-term financing totaled approximately $3.5 billion. Of this total, $3.0 billion supports commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2012, and 2011, was 1.7 percent and 1.9 percent, respectively.
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 crude production, natural gas production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; refining operations, petrochemical manufacturing, fuel sales and power generation in Asia; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several refining, petrochemical manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. 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 16 percent, 19 percent and 18 percent in the years 2012, 2011 and 2010, respectively.
Equity Company
ExxonMobil
ExxonMobil
ExxonMobil
Financial Summary
Total
Share
Total
Share
Total
Share
(millions of dollars)
Total revenues
224,953
67,572
204,635
65,147
153,020
48,355
Income before income taxes
69,411
20,882
68,908
20,892
48,075
14,735
Income taxes
20,703
5,868
19,812
5,603
13,962
4,058
Income from equity affiliates
48,708
15,014
49,096
15,289
34,113
10,677
Current assets
59,612
18,483
52,879
17,317
48,573
15,860
Long-term assets
111,131
33,798
96,908
30,833
90,646
29,805
Total assets
170,743
52,281
149,787
48,150
139,219
45,665
Current liabilities
49,698
14,265
41,016
12,454
33,160
10,260
Long-term liabilities
68,855
19,715
62,472
18,728
59,596
17,976
Net assets
52,190
18,301
46,299
16,968
46,463
17,429
A list of significant equity companies as of December 31, 2012, together with the Corporation’s percentage ownership interest, is detailed below:
Percentage
Percentage
Ownership
Ownership
Interest
Interest
Upstream
Downstream
Aera Energy LLC
Chalmette Refining, LLC
BEB Erdgas und Erdoel GmbH & Co. KG
Fujian Refining & Petrochemical Co. Ltd.
Cameroon Oil Transportation Company S.A.
Saudi Aramco Mobil Refinery Company Ltd.
Castle Peak Power Company Limited
TonenGeneral Sekiyu K.K.
Cross Timbers Energy, LLC
Golden Pass LNG Terminal LLC
Chemical
Nederlandse Aardolie Maatschappij B.V.
Al-Jubail Petrochemical Company
Qatar Liquefied Gas Company Limited
Infineum Holdings B.V.
Qatar Liquefied Gas Company Limited (2)
Saudi Yanbu Petrochemical Co.
Ras Laffan Liquefied Natural Gas Company Limited
Ras Laffan Liquefied Natural Gas Company Limited (II)
Ras Laffan Liquefied Natural Gas Company Limited (3)
South Hook LNG Terminal Company Limited
Tengizchevroil, LLP
Terminale GNL Adriatico S.r.l.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Investments, Advances and Long-Term Receivables
Dec. 31,
Dec. 31,
(millions of dollars)
Companies carried at equity in underlying assets
Investments
18,530
16,968
Advances
9,959
9,740
Total equity company investments and advances
28,489
26,708
Companies carried at cost or less and stock investments carried at fair value
1,544
Long-term receivables and miscellaneous investments at cost or less, net of reserves
of $2,499 million and $469 million
5,792
6,081
Total
34,718
34,333
9. Property, Plant and Equipment and Asset Retirement Obligations
December 31, 2012
December 31, 2011
Property, Plant and Equipment
Cost
Net
Cost
Net
(millions of dollars)
Upstream
313,181
181,795
283,710
163,975
Downstream
53,737
23,053
67,900
28,801
Chemical
29,437
14,085
30,405
14,469
Other
12,959
8,016
11,980
7,419
Total
409,314
226,949
393,995
214,664
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 $182,365 million at the end of 2012 and $179,331 million at the end of 2011. Interest capitalized in 2012, 2011 and 2010 was $506 million, $593 million and $532 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 (unobservable inputs) 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:
(millions of dollars)
Beginning balance
10,578
9,614
Accretion expense and other provisions
Reduction due to property sales
(176)
(854)
Payments made
(816)
(662)
Liabilities incurred
Foreign currency translation
(62)
Revisions
1,225
1,844
Ending balance
11,973
10,578
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 does not necessarily have the same meaning as under SEC Rule 13q-1 relating to government payment reporting. For example, a single project for purposes of the rule may encompass numerous properties, agreements, investments, developments, phases, work efforts, activities, and components, each of which we may also informally describe as a “project.”
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:
(millions of dollars)
Balance beginning at January 1
2,881
2,893
2,005
Additions pending the determination of proved reserves
1,103
Charged to expense
(95)
(213)
(104)
Reclassifications to wells, facilities and equipment based on the
determination of proved reserves
(631)
(149)
(136)
Divestments/Other
(344)
Ending balance at December 31
2,679
2,881
2,893
Ending balance attributed to equity companies included above
-
-
Period end capitalized suspended exploratory well costs:
(millions of dollars)
Capitalized for a period of one year or less
1,103
Capitalized for a period of between one and five years
1,176
1,922
1,294
Capitalized for a period of between five and ten years
Capitalized for a period of greater than ten years
Capitalized for a period greater than one year - subtotal
1,813
2,571
1,790
Total
2,679
2,881
2,893
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.
Number of projects with first capitalized well drilled in the preceding 12 months
Number of projects that have exploratory well costs capitalized for a period
of greater than 12 months
Total
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Of the 45 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2012, 17 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 28 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 28 projects, which total $557 million.
Years
Dec. 31,
Wells
Country/Project
Drilled
Comment
(millions of dollars)
Angola
- Perpetua-Zina-Acacia
2008 - 2009
Oil field near Pazflor development, awaiting capacity in existing/planned
infrastructure.
Australia
- East Pilchard
Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
infrastructure.
- SE Longtom
Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
Indonesia
- Natuna
1981 - 1983
Development activity under way, while continuing discussions with the government
on contract terms pursuant to executed Heads of Agreement.
Kazakhstan
- Kairan
2004 - 2007
Evaluating commercialization and field development alternatives, while continuing
discussions with the government regarding the development plan.
Malaysia
- Besar
1992 - 2010
Gas field off the east coast of Malaysia; progressing development plan.
- Bindu
Awaiting capacity in existing/planned infrastructure.
Nigeria
- Bolia
2002 - 2006
Evaluating development plan, while continuing discussions with the government
regarding regional hub strategy.
- Bosi
2002 - 2006
Development activity under way, while continuing discussions with the government
regarding development plan.
- Bosi Central
Development activity under way, while continuing discussions with the government
regarding development plan.
- Pegi
Awaiting capacity in existing/planned infrastructure.
- Usan South Strip
Evaluating development plans to tie into planned infrastructure.
- Other (5 projects)
2001 - 2002
Evaluating and pursuing development of several additional discoveries.
Norway
- Gamma
2008 - 2009
Evaluating development plan for tieback to existing production facilities.
- H-North
Progressing development and commercialization plans.
- Lavrans
1995 - 1999
Development awaiting capacity in existing Kristin production facility; evaluating
development concepts for phased ullage scenarios.
- Other (5 projects)
2008 - 2010
Evaluating development plans, including potential for tieback to existing production
facilities.
Papua New Guinea
- Juha
Working on development plans to tie into planned LNG facilities.
United Kingdom
- Phyllis
Evaluating development plan for tieback to existing production facilities.
United States
- Tip Top
Evaluating development concept and requisite facility upgrades.
Total 2012 (28 projects)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Leased Facilities
At December 31, 2012, 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 $8,181 million as indicated in the table. Estimated related rental income from noncancelable subleases is $111 million.
Related
Lease Payments
Sublease
Under Minimum
Rental
Commitments
Income
(millions of dollars)
2,254
2,041
1,381
2018 and beyond
1,467
Total
8,181
Net rental cost under both cancelable and noncancelable operating leases incurred during 2012, 2011 and 2010 were as follows:
(millions of dollars)
Rental cost
3,851
4,061
3,762
Less sublease rental income
Net rental cost
3,807
3,987
3,672
12. Earnings Per Share
Earnings per common share
Net income attributable to ExxonMobil (millions of dollars)
44,880
41,060
30,460
Weighted average number of common shares outstanding (millions of shares)
4,628
4,870
4,885
Earnings per common share (dollars)
9.70
8.43
6.24
Earnings per common share - assuming dilution
Net income attributable to ExxonMobil (millions of dollars)
44,880
41,060
30,460
Weighted average number of common shares outstanding (millions of shares)
4,628
4,870
4,885
Effect of employee stock-based awards
-
Weighted average number of common shares outstanding - assuming dilution
4,628
4,875
4,897
Earnings per common share - assuming dilution (dollars)
9.70
8.42
6.22
Dividends paid per common share (dollars)
2.18
1.85
1.74
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, including capitalized lease obligations, was $8.5 billion and $9.8 billion at December 31, 2012, and 2011, respectively, as compared to recorded book values of $7.9 billion and $9.3 billion at December 31, 2012, and 2011, respectively. The fair value of long-term debt by hierarchy level at December 31, 2012 is shown below:
As of December 31, 2012
Level 1
Level 2
Level 3
Total
(millions of dollars)
Long-term debt fair value
6,482
1,480
8,458
The fair value hierarchy for long-term debt is primarily Level 1 and represents quoted prices in active markets. Level 2 includes debt whose fair value is based upon a publicly available index. The Level 3 amount is primarily capitalized leases whose value is typically determined through the use of present value and specific contract terms.
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 $2 million at year-end 2012 and a net liability of $3 million at year-end 2011. 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 (observable quoted prices on active exchanges) or Level 2 (derivatives that are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices) inputs.
The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $(23) million, $131 million and $221 million during 2012, 2011 and 2010, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. Long-Term Debt
At December 31, 2012, long-term debt consisted of $7,325 million due in U.S. dollars and $603 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 $1,025 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing in each of the four years after December 31, 2013, in millions of dollars, are: 2014 - $907; 2015 - $710; 2016 - $454; and 2017 - $814. At December 31, 2012, the Corporation’s unused long-term credit lines were not material.
Summarized long-term debt at year-end 2012 and 2011 are shown in the table below:
(millions of dollars)
XTO Energy Inc. (1)
6.250% senior note due 2013
-
4.625% senior note due 2013
-
5.750% senior note due 2013
-
4.900% senior note due 2014
5.000% senior note due 2015
5.300% senior note due 2015
5.650% senior note due 2016
6.250% senior note due 2017
5.500% senior note due 2018
6.500% senior note due 2018
6.100% senior note due 2036
6.750% senior note due 2037
6.375% senior note due 2038
Mobil Services (Bahamas) Ltd.
Variable note due 2035 (2)
-
Variable note due 2034 (3)
Mobil Producing Nigeria Unlimited (4)
Variable notes due 2013-2019
Esso (Thailand) Public Company Ltd. (5)
Variable notes due 2014-2017
Mobil Corporation
8.625% debentures due 2021
Industrial revenue bonds due 2014-2051 (6)
2,690
2,315
Other U.S. dollar obligations (7)
Other foreign currency obligations
Capitalized lease obligations (8)
Total long-term debt
7,928
9,322
(1) Includes premiums of $326 million.
(2) Average effective interest rate of 0.2% in 2011.
(3) Average effective interest rate of 0.5% in 2012 and 0.3% in 2011.
(4) Average effective interest rate of 4.6% in 2012 and 4.2% in 2011.
(5) Average effective interest rate of 3.5% in 2012 and 3.2% in 2011.
(6) Average effective interest rate of 0.1% in 2012 and 0.1% in 2011.
(7) Average effective interest rate of 2.7% in 2012 and 4.8% in 2011.
(8) Average imputed interest rate of 7.6% in 2012 and 8.5% in 2011.
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 2012, remaining shares available for award under the 2003 Incentive Program were 124,736 thousand.
Restricted Stock. Awards totaling 10,017 thousand, 10,533 thousand, and 10,648 thousand (excluding XTO merger-related grants) of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2012, 2011 and 2010, 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. These shares 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 may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. 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.
Additionally, in 2010 long-term incentive awards totaling 4,206 thousand shares of restricted (nonvested) common stock, with a value of $250 million, were granted in association with the XTO merger. The majority of these awards vest over periods of up to three years after the initial grant.
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, 2012.
Weighted Average
Grant-Date
Restricted stock and units outstanding
Shares
Fair Value per Share
(thousands)
(dollars)
Issued and outstanding at January 1
46,781
70.76
2011 award issued in 2012
10,522
79.52
Vested
(10,537)
65.56
Forfeited
(315)
68.50
Issued and outstanding at December 31
46,451
73.94
Value of restricted stock and units
Grant price (dollars)
87.24
79.52
66.07
Value at date of grant:
(millions of dollars)
Restricted stock and units settled in stock
Merger-related granted and converted XTO awards
-
-
Units settled in cash
Total value
As of December 31, 2012, there was $2,179 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 units was $854 million, $793 million and $801 million for 2012, 2011 and 2010, respectively. The income tax benefit recognized in income related to this compensation expense was $79 million, $73 million and $81 million for the same periods, respectively. The fair value of shares and units vested in 2012, 2011 and 2010 was $926 million, $801 million and $718 million, respectively. Cash payments of $66 million, $46 million and $42 million for vested restricted stock units settled in cash were made in 2012, 2011 and 2010, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options. The Corporation has not granted any stock options under the 2003 Incentive Program and all stock options granted under the prior program were exercised by the end of 2011. In 2010, the Corporation granted 12,393 thousand of converted XTO stock options with a grant-date fair value of $182 million as a result of the XTO merger. These stock options generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels. Some stock option tranches vest only when the common stock price reaches specified levels. There were 2,355 thousand stock options, with an average exercise price of $78.60, outstanding at December 31, 2012.
Cash received from stock option exercises was $193 million, $924 million and $1,043 million for 2012, 2011 and 2010, respectively. The cash tax benefit realized for the options exercised was $54 million, $221 million and $89 million for 2012, 2011 and 2010, respectively. The aggregate intrinsic value of stock options exercised in 2012, 2011 and 2010 was $79 million, $986 million and $539 million, respectively.
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.
On June 30, 2011, a state district court jury in Baltimore County, Maryland returned a verdict against Exxon Mobil Corporation in Allison, et al v. Exxon Mobil Corporation, a case involving an accidental 26,000 gallon gasoline leak at a suburban Baltimore service station. The verdict included approximately $497 million in compensatory damages and approximately $1.0 billion in punitive damages in a finding that ExxonMobil fraudulently misled the plaintiff-residents about the events leading up to the leak, the leak’s discovery, and the nature and extent of any groundwater contamination. ExxonMobil believes the verdict is not justified by the evidence and that the amount of the compensatory award is grossly excessive and the imposition of punitive damages is improper and unconstitutional. The trial court denied a post-trial motion that ExxonMobil filed to overturn the punitive damages verdict and entered a final judgment in the amount of $1,488 million. ExxonMobil appealed the verdict and judgment. In a prior trial involving the same leak and different plaintiffs, the jury awarded compensatory damages but rejected the plaintiffs’ punitive damage claims. Those plaintiffs did not appeal the jury’s denial of punitive damages. On February 9, 2012, the Maryland Court of Special Appeals reversed in part and affirmed in part the trial court's decision on compensatory damages in that case. The Maryland Court of Appeals granted writs of certiorari to both parties in response to their separate petitions seeking reversals of portions of the Court of Special Appeals' decision. The appeals in both of these cases were consolidated before the Maryland Court of Appeals and arguments were held on November 5, 2012. On February 26, 2013, the Maryland Court of Appeals issued its opinion in the consolidated appeal. The court unanimously reversed the fraud and punitive damages judgment, and also reversed a majority of the compensatory damage claims. The court remanded a limited number of claims related to alleged property damage for a new trial.
Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2012, 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, 2012
Equity Company
Other Third-Party
Obligations (1)
Obligations
Total
(millions of dollars)
Guarantees
Debt-related
2,423
2,476
Other
2,729
4,994
7,723
Total
5,152
5,047
10,199
(1) ExxonMobil share.
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Payments Due by Period
2018 and
Beyond
Total
(millions of dollars)
Unconditional purchase obligations (1)
1,127
(1) Undiscounted obligations of $1,127 million mainly pertain to pipeline throughput agreements and include $584 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $198 million, totaled $929 million.
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. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million.
On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment 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. The ICSID arbitration proceeding is continuing and a hearing on the merits was held in February 2012. At this time, the net impact of these matters 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. 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.
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
(percent)
Weighted-average assumptions used to determine
benefit obligations at December 31
Discount rate
4.00
5.00
3.80
4.00
4.00
5.00
Long-term rate of compensation increase
5.75
5.75
5.50
5.40
5.75
5.75
(millions of dollars)
Change in benefit obligation
Benefit obligation at January 1
17,035
15,007
29,068
25,722
7,880
7,331
Service cost
Interest cost
1,145
1,267
Actuarial loss/(gain)
2,553
1,954
2,335
3,086
1,035
Benefits paid (1) (2)
(1,294)
(1,264)
(1,330)
(1,470)
(476)
(473)
Foreign exchange rate changes
-
-
(303)
(11)
Japan restructuring and other divestments
-
-
(3,952)
(16)
-
-
Plan amendments, other
-
-
Benefit obligation at December 31
19,779
17,035
28,670
29,068
9,058
7,880
Accumulated benefit obligation at December 31
15,902
14,081
24,345
25,480
-
-
(1) Benefit payments for funded and unfunded plans.
(2) For 2012 and 2011, other postretirement benefits paid are net of $23 million and $29 million of Medicare subsidy receipts, respectively.
For U.S. plans, the discount rate is determined by constructing a portfolio of 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 an initial health care cost trend rate of 5.0 percent that declines to 4.5 percent by 2015. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $74 million and the postretirement benefit obligation by $871 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $57 million and the postretirement benefit obligation by $700 million.
Pension Benefits
Other Postretirement
U.S.
Non-U.S.
Benefits
(millions of dollars)
Change in plan assets
Fair value at January 1
10,656
10,835
17,117
16,765
Actual return on plan assets
1,457
1,541
-
Foreign exchange rate changes
-
-
(192)
-
-
Company contribution
1,560
1,604
1,623
Benefits paid (1)
(1,041)
(1,054)
(922)
(1,046)
(60)
(59)
Japan restructuring and other divestments
-
-
(1,696)
(7)
-
-
Other
-
-
(16)
(149)
-
-
Fair value at December 31
12,632
10,656
18,090
17,117
(1) Benefit payments for funded plans.
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.
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans
(4,438)
(4,141)
(3,247)
(5,319)
Unfunded plans
(2,709)
(2,238)
(7,333)
(6,632)
Total
(7,147)
(6,379)
(10,580)
(11,951)
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
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1)
(7,147)
(6,379)
(10,580)
(11,951)
(8,477)
(7,342)
Amounts recorded in the consolidated balance
sheet consist of:
Other assets
-
-
Current liabilities
(279)
(237)
(352)
(346)
(356)
(341)
Postretirement benefits reserves
(6,869)
(6,143)
(10,277)
(11,850)
(8,121)
(7,001)
Total recorded
(7,147)
(6,379)
(10,580)
(11,951)
(8,477)
(7,342)
Amounts recorded in accumulated other
comprehensive income consist of:
Net actuarial loss/(gain)
7,451
6,475
10,904
11,170
3,132
2,291
Prior service cost
Total recorded in accumulated other
comprehensive income
7,518
6,549
11,662
11,915
3,217
2,410
(1) Fair value of assets less benefit obligation shown on the preceding page.
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
Weighted-average assumptions used to
determine net periodic benefit cost for
years ended December 31
(percent)
Discount rate
5.00
5.50
6.00
4.00
4.80
5.20
5.00
5.50
6.00
Long-term rate of return on funded assets
7.25
7.50
7.50
6.60
6.80
6.70
7.25
7.50
7.50
Long-term rate of compensation increase
5.75
5.25
5.25
5.40
5.20
5.00
5.75
5.25
5.25
Components of net periodic benefit cost
(millions of dollars)
Service cost
Interest cost
1,145
1,267
1,175
Expected return on plan assets
(789)
(769)
(726)
(1,109)
(1,168)
(1,010)
(38)
(41)
(37)
Amortization of actuarial loss/(gain)
Amortization of prior service cost
Net pension enhancement and
curtailment/settlement cost (1)
1,540
-
-
-
Net periodic benefit cost
1,612
1,349
1,388
3,185
1,457
1,292
(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” (See Note 20).
Changes in amounts recorded in accumulated
other comprehensive income:
Net actuarial loss/(gain)
1,885
2,218
1,906
4,133
1,202
1,008
Amortization of actuarial (loss)/gain
(909)
(771)
(846)
(2,384)
(681)
(563)
(170)
(162)
(147)
Prior service cost/(credit)
-
-
-
-
Amortization of prior service (cost)/credit
(7)
(9)
(2)
(117)
(103)
(84)
(34)
(35)
(52)
Foreign exchange rate changes
-
-
-
(90)
-
Total recorded in other comprehensive income
1,438
(724)
(253)
3,446
Total recorded in net periodic benefit cost and
other comprehensive income, before tax
2,581
2,787
2,932
4,903
2,103
1,487
Costs for defined contribution plans were $382 million, $378 million and $347 million in 2012, 2011 and 2010, respectively.
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
(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
U.S. pension
(969)
(1,438)
Non-U.S. pension
(3,446)
(811)
Other postretirement benefits
(807)
(271)
(80)
Total (charge)/credit to other comprehensive income, before tax
(1,523)
(5,155)
(167)
(Charge)/credit to income tax (see Note 4)
1,495
(Charge)/credit to investment in equity companies
(49)
(30)
(Charge)/credit to other comprehensive income including noncontrolling
interests, after tax
(1,179)
(3,690)
(121)
Charge/(credit) to equity of noncontrolling interests
(124)
(Charge)/credit to other comprehensive income attributable to ExxonMobil
(1,303)
(3,402)
(26)
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 is 50 percent equity securities and 50 percent debt securities. The target asset allocation for the non-U.S. plans in aggregate is 50 percent equity securities and 50 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2012 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
U.S. Pension
Non-U.S. Pension
Fair Value Measurement
Fair Value Measurement
at December 31, 2012, Using:
at December 31, 2012, Using:
Quoted
Quoted
Prices
Prices
in Active
Significant
in Active
Significant
Markets for
Other
Significant
Markets for
Other
Significant
Identical
Observable
Unobservable
Identical
Observable
Unobservable
Assets
Inputs
Inputs
Assets
Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(Level 1)
(Level 2)
(Level 3)
Total
(millions of dollars)
Asset category:
Equity securities
U.S.
-
2,600
(1)
-
2,600
-
2,671
(1)
-
2,671
Non-U.S.
-
3,227
(1)
-
3,227
(2)
5,308
(1)
-
5,511
Private equity
-
-
(3)
-
-
(3)
Debt securities
Corporate
-
3,872
(4)
-
3,872
-
2,005
(4)
-
2,005
Government
-
2,223
(4)
-
2,223
(5)
6,643
(4)
-
6,914
Asset-backed
-
(4)
-
-
(4)
-
Private mortgages
-
-
-
-
-
-
(6)
Real estate funds
-
-
-
-
-
-
(7)
Cash
-
(8)
-
(9)
-
Total at fair value
-
12,130
12,619
16,757
18,070
Insurance contracts
at contract value
Total plan assets
12,632
18,090
(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 private mortgages, fair value is estimated to equal the principal outstanding at the measurement date.
(7) For real estate funds, fair value is based on appraised values developed using comparable market transactions.
(8) 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.
(9) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Postretirement
Fair Value Measurement
at December 31, 2012, Using:
Quoted
Prices
in Active
Significant
Markets for
Other
Significant
Identical
Observable
Unobservable
Assets
Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(millions of dollars)
Asset category:
Equity securities
U.S.
-
(1)
-
Non-U.S.
-
(1)
-
Private equity
-
-
(2)
Debt securities
Corporate
-
(3)
-
Government
-
(3)
-
Asset-backed
-
(3)
-
Cash
-
-
Total at fair value
-
(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 2012 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:
Pension
Other
U.S.
Non-U.S.
Postretirement
Private
Private
Private
Real
Private
Equity
Equity
Mortgages
Estate
Equity
(millions of dollars)
Fair value at January 1
Net realized gains/(losses)
-
(14)
-
Net unrealized gains/(losses)
(1)
-
Net purchases/(sales)
(12)
-
(89)
-
Fair value at December 31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The 2011 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, 2011, Using:
at December 31, 2011, 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.
-
2,247
(1)
-
2,247
-
2,589
(1)
-
2,589
Non-U.S.
-
2,636
(1)
-
2,636
(2)
4,835
(1)
-
5,029
Private equity
-
-
(3)
-
-
(3)
Debt securities
Corporate
-
2,728
(4)
-
2,728
(5)
1,857
(4)
-
1,859
Government
-
2,482
(4)
-
2,482
(5)
6,317
(4)
-
6,503
Asset-backed
-
(4)
-
-
(4)
-
Private mortgages
-
-
-
-
-
-
(6)
Real estate funds
-
-
-
-
-
-
(7)
Cash
-
(8)
-
(9)
-
Total at fair value
-
10,175
10,633
15,713
16,965
Insurance contracts
at contract value
Total plan assets
10,656
17,117
(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 private mortgages, fair value is estimated to equal the principal outstanding at the measurement date.
(7) For real estate funds, fair value is based on appraised values developed using comparable market transactions.
(8) 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.
(9) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Postretirement
Fair Value Measurement
at December 31, 2011, 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.
-
(1)
-
Non-U.S.
-
(1)
-
Private equity
-
-
(2)
Debt securities
Corporate
-
(3)
-
Government
-
(3)
-
Asset-backed
-
(3)
-
Cash
-
-
Total at fair value
-
(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 2011 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:
Pension
Other Postretirement
U.S.
Non-U.S.
Private
Private
Private
Private
Real
Private
Private
Equity
Mortgages
Equity
Mortgages
Estate
Equity
Mortgages
(millions of dollars)
Fair value at January 1
Net realized gains/(losses)
-
-
-
Net unrealized gains/(losses)
-
-
-
Net purchases/(sales)
(7)
(133)
-
(29)
-
(2)
Fair value at December 31
-
-
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.
(millions of dollars)
For funded pension plans with an accumulated benefit obligation
in excess of plan assets:
Projected benefit obligation
17,070
14,797
9,422
17,668
Accumulated benefit obligation
14,171
12,606
8,184
16,175
Fair value of plan assets
12,631
10,655
7,048
12,832
For unfunded pension plans:
Projected benefit obligation
2,709
2,238
7,333
6,632
Accumulated benefit obligation
1,731
1,475
6,103
5,753
Other
Pension Benefits
Postretirement
U.S.
Non-U.S.
Benefits
(millions of dollars)
Estimated 2013 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain) (1)
1,173
Prior service cost (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.
Pension Benefits
Other Postretirement Benefits
Medicare
U.S.
Non-U.S.
Gross
Subsidy Receipt
(millions of dollars)
Contributions expected in 2013
1,250
-
-
Benefit payments expected in:
1,643
1,237
1,611
1,237
1,597
1,294
1,558
1,329
1,510
1,384
2018 - 2022
6,716
7,319
2,633
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 assess its performance; and (3) for which discrete financial information is available.
Earnings after income tax include transfers at estimated market prices.
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 $202 million, $165 million and $41 million in 2012, 2011 and 2010, respectively.
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, 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 above
1,759
11,900
1,267
(492)
15,010
Sales and other operating revenue (1)
11,472
28,854
125,088
248,959
14,723
24,003
453,123
Intersegment revenue
8,764
47,507
20,963
62,130
12,409
9,750
-
Depreciation and depletion expense
5,104
7,340
1,280
15,888
Interest revenue
-
-
-
-
-
-
Interest expense
-
(1)
Income taxes
2,025
25,362
1,811
1,892
(1,032)
31,045
Additions to property, plant and equipment
9,697
21,769
1,153
1,083
35,179
Investments in equity companies
4,020
9,147
2,069
3,143
(277)
18,530
Total assets
86,146
140,848
18,451
40,956
7,238
18,886
21,270
333,795
As of December 31, 2011
Earnings after income tax
5,096
29,343
2,268
2,191
2,215
2,168
(2,221)
41,060
Earnings of equity companies above
2,045
11,768
1,365
(447)
15,289
Sales and other operating revenue (1)
14,023
32,419
120,844
257,779
15,466
26,476
467,029
Intersegment revenue
9,807
49,910
18,489
73,549
12,226
10,563
-
Depreciation and depletion expense
4,879
7,021
1,560
15,583
Interest revenue
-
-
-
-
-
-
Interest expense
(1)
Income taxes
2,852
25,755
1,123
1,027
(867)
31,051
Additions to property, plant and equipment
10,887
18,934
1,334
33,638
Investments in equity companies
2,963
8,439
1,358
3,973
(228)
16,968
Total assets
82,900
127,977
18,354
51,132
7,245
19,862
23,582
331,052
As of December 31, 2010
Earnings after income tax
4,272
19,825
2,797
2,422
2,491
(2,117)
30,460
Earnings of equity companies above
1,261
8,415
1,163
(581)
10,677
Sales and other operating revenue (1)
8,895
26,046
93,599
206,042
13,402
22,119
370,125
Intersegment revenue
8,102
39,066
13,546
52,697
9,694
8,421
-
Depreciation and depletion expense
3,506
7,574
1,565
14,760
Interest revenue
-
-
-
-
-
-
Interest expense
Income taxes
2,219
18,627
(1,288)
21,561
Additions to property, plant and equipment
52,300
16,937
1,332
1,733
74,156
Investments in equity companies
2,636
9,625
1,240
3,586
(197)
17,429
Total assets
76,725
115,646
18,378
47,402
7,148
19,087
18,124
302,510
(1) Sales and other operating revenue includes sales-based taxes of $32,409 million for 2012, $33,503 million for 2011 and $28,547 million for 2010. See Note 1, Summary of Accounting Policies.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Geographic
Sales and other operating revenue (1)
(millions of dollars)
United States
151,298
150,343
115,906
Non-U.S.
301,825
316,686
254,219
Total
453,123
467,029
370,125
Significant non-U.S. revenue sources include:
Canada
34,325
34,626
27,243
United Kingdom
34,134
34,833
24,637
Belgium
23,567
26,926
21,139
France
19,601
18,510
13,920
Italy
18,228
16,288
14,132
Germany
16,451
17,034
14,301
Singapore
14,606
14,400
11,088
Japan
14,162
31,925
27,143
(1) Sales and other operating revenue includes sales-based taxes of $32,409 million for 2012, $33,503 million for 2011 and $28,547 million for 2010. See Note 1, Summary of Accounting Policies.
Long-lived assets
(millions of dollars)
United States
94,336
91,146
86,021
Non-U.S.
132,613
123,518
113,527
Total
226,949
214,664
199,548
Significant non-U.S. long-lived assets include:
Canada
31,979
24,458
20,879
Australia
13,415
9,474
6,570
Nigeria
12,216
11,806
11,429
Singapore
9,700
9,285
8,610
Angola
8,238
10,395
8,570
Kazakhstan
7,785
7,022
5,938
Norway
7,040
6,039
6,988
United Kingdom
5,472
5,008
6,177
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Income, Sales-Based and Other Taxes
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
1,791
25,650
27,441
1,547
28,849
30,396
1,224
21,093
22,317
Deferred - net
1,097
1,816
2,913
1,577
(1,417)
(1,191)
(1,142)
U.S. tax on non-U.S. operations
-
-
-
Total federal and non-U.S.
2,977
27,466
30,443
3,139
27,432
30,571
1,319
19,902
21,221
State
-
-
-
Total income tax expense
3,579
27,466
31,045
3,619
27,432
31,051
1,659
19,902
21,561
Sales-based taxes
5,785
26,624
32,409
5,652
27,851
33,503
6,182
22,365
28,547
All other taxes and duties
Other taxes and duties
1,406
34,152
35,558
1,539
38,434
39,973
35,342
36,118
Included in production and
manufacturing expenses
1,242
1,308
2,550
1,342
1,425
2,767
1,001
1,237
2,238
Included in SG&A expenses
Total other taxes and duties
2,802
36,055
38,857
3,062
40,482
43,544
1,978
37,149
39,127
Total
12,166
90,145
102,311
12,333
95,765
108,098
9,819
79,416
89,235
All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net charges of $244 million in 2012 and $175 million in 2010 and a net credit of $330 million in 2011 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 2012, 2011 and 2010 is as follows:
(millions of dollars)
Income before income taxes
United States
11,222
11,511
7,711
Non-U.S.
67,504
61,746
45,248
Total
78,726
73,257
52,959
Theoretical tax
27,554
25,640
18,536
Effect of equity method of accounting
(5,254)
(5,351)
(3,737)
Non-U.S. taxes in excess of theoretical U.S. tax
8,434
10,385
7,293
U.S. tax on non-U.S. operations
State taxes, net of federal tax benefit
Other U.S.
(169)
(798)
Total income tax expense
31,045
31,051
21,561
Effective tax rate calculation
Income taxes
31,045
31,051
21,561
ExxonMobil share of equity company income taxes
5,859
5,603
4,058
Total income taxes
36,904
36,654
25,619
Net income including noncontrolling interests
47,681
42,206
31,398
Total income before taxes
84,585
78,860
57,017
Effective income tax rate
44%
46%
45%
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:
(millions of dollars)
Property, plant and equipment
48,720
45,951
Other liabilities
3,680
4,281
Total deferred tax liabilities
52,400
50,232
Pension and other postretirement benefits
(8,041)
(7,930)
Asset retirement obligations
(5,826)
(5,302)
Tax loss carryforwards
(2,989)
(3,166)
Other assets
(6,135)
(7,079)
Total deferred tax assets
(22,991)
(23,477)
Asset valuation allowances
1,615
1,304
Net deferred tax liabilities
31,024
28,059
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
(millions of dollars)
Other current assets
(3,540)
(4,549)
Other assets, including intangibles, net
(3,269)
(4,218)
Accounts payable and accrued liabilities
Deferred income tax liabilities
37,570
36,618
Net deferred tax liabilities
31,024
28,059
The Corporation had $43 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.
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. Resolution of the related 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 25 percent in the next 12 months, with no material impact on near-term earnings. Given the long time periods involved in resolving tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.
The following table summarizes the movement in unrecognized tax benefits.
Gross unrecognized tax benefits
(millions of dollars)
Balance at January 1
4,922
4,148
4,725
Additions based on current year's tax positions
1,662
Additions for prior years' tax positions
2,559
Reductions for prior years' tax positions
(535)
(329)
(505)
Reductions due to lapse of the statute of limitations
(79)
-
(534)
Settlements with tax authorities
(855)
(145)
(999)
Foreign exchange effects/other
(11)
(25)
Balance at December 31
7,663
4,922
4,148
The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2012, 2011 and 2010 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Country of Operation
Open Tax Years
Abu Dhabi
2000 - 2012
Angola
2009 - 2012
Australia:
2000 - 2003
2005 - 2012
Canada
2005 - 2012
Equatorial Guinea
2007 - 2012
Malaysia
2006 - 2012
Nigeria
1998 - 2012
Norway
2000 - 2012
United Kingdom
2010 - 2012
United States
2005 - 2012
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 $46 million and $62 million in interest expense on income tax reserves in 2012 and 2011, respectively. For 2010, interest expense was a credit of $39 million, reflecting the effect of credits from the net favorable resolution of prior year tax positions. The related interest payable balances were $385 million and $662 million at December 31, 2012, and 2011, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20. Japan Restructuring
On June 1, 2012, the Corporation completed the restructuring of its Downstream and Chemical holdings in Japan. Under the restructuring, TonenGeneral Sekiyu K. K. (TG), a consolidated subsidiary owned 50 percent by the Corporation, purchased for $3.9 billion the Corporation’s shares of a wholly-owned affiliate in Japan, EMG Marketing Godo Kaisha (previously known as ExxonMobil Yugen Kaisha), which resulted in TG acquiring approximately 200 million of its shares owned by the Corporation along with other assets. As a result of the restructuring, the Corporation’s effective ownership of TG was reduced to approximately 22 percent and a net gain of $6.5 billion was recognized. The gain is included in “Other income” partially offset by amounts included in “Income taxes” and “Net income attributable to noncontrolling interests.”
The gain includes $1.9 billion of the Corporation’s share of other comprehensive income recycled into earnings (see note 1 below). The gain also includes remeasurement of TG’s shares that the Corporation continues to own to $0.7 billion, based on TG’s share price on the Tokyo Stock Exchange. The Corporation accounts for its remaining investment using the equity method.
Summarized balance sheet for the Japan entities subject to the restructuring follows:
June 1, 2012
(millions of dollars)
Assets
Current assets
6,391
Net property, plant and equipment
4,700
Other assets
Total assets
12,080
Liabilities
Current liabilities
7,398
Long-term debt
Postretirement benefits reserves
2,066
Other long-term obligations
Total liabilities
10,312
Equity
ExxonMobil share of equity (1)
(256)
Noncontrolling interests
2,024
Total equity
1,768
Total liabilities and equity
12,080
(1) The accumulated other comprehensive income associated with the Japan restructuring was recycled into earnings. At June 1, 2012, ExxonMobil’s share of accumulated other comprehensive income was a benefit of $1.9 billion, including $2.5 billion related to cumulative translation adjustments offset by $0.6 billion related to postretirement benefits reserves adjustments.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the 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 $2,832 million in 2012, $2,600 million in 2011, and $249 million in 2010. 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
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
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
14,055
Exploration expenses
1,840
Depreciation and depletion
4,862
1,559
2,879
1,785
12,197
Taxes other than income
1,963
1,702
2,248
6,961
Related income tax
1,561
5,413
8,091
6,616
22,682
Results of producing activities for consolidated
subsidiaries
1,152
2,233
1,999
5,276
3,009
14,261
Equity Companies
2012 - Revenue
Sales to third parties
1,284
-
6,380
-
20,017
-
27,681
Transfers
1,108
-
-
5,693
-
6,868
2,392
-
6,447
-
25,710
-
34,549
Production costs excluding taxes
-
-
-
1,320
Exploration expenses
-
-
-
-
Depreciation and depletion
-
-
-
1,004
Taxes other than income
-
3,569
-
6,658
-
10,269
Related income tax
-
-
-
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
27,063
Canada/
United
South
Australia/
Results of Operations
States
America
Europe
Africa
Asia
Oceania
Total
(millions of dollars)
Consolidated Subsidiaries
2011 - Revenue
Sales to third parties
8,579
1,056
8,050
3,507
6,813
1,061
29,066
Transfers
8,190
7,022
7,694
16,704
9,388
1,213
50,211
16,769
8,078
15,744
20,211
16,201
2,274
79,277
Production costs excluding taxes
4,107
2,751
2,722
2,608
1,672
14,357
Exploration expenses
2,081
Depreciation and depletion
4,664
1,928
2,159
1,680
11,647
Taxes other than income
2,157
2,055
2,164
7,381
Related income tax
2,445
6,842
7,888
6,026
24,523
Results of producing activities for consolidated
subsidiaries
3,128
3,009
3,022
5,268
4,041
19,288
Equity Companies
2011 - Revenue
Sales to third parties
1,356
-
5,580
-
18,855
-
25,791
Transfers
1,163
-
-
5,666
-
6,932
2,519
-
5,683
-
24,521
-
32,723
Production costs excluding taxes
-
-
-
1,175
Exploration expenses
-
-
-
-
Depreciation and depletion
-
-
-
Taxes other than income
-
2,995
-
6,173
-
9,204
Related income tax
-
-
-
8,036
-
8,883
Results of producing activities for equity companies
1,840
-
1,353
-
9,358
-
12,551
Total results of operations
4,968
3,009
4,375
5,268
13,399
31,839
Consolidated Subsidiaries
2010 - Revenue
Sales to third parties
5,334
1,218
6,055
4,227
4,578
22,108
Transfers
7,070
5,832
7,120
13,295
6,031
1,123
40,471
12,404
7,050
13,175
17,522
10,609
1,819
62,579
Production costs excluding taxes
2,794
2,612
2,717
2,215
1,308
12,108
Exploration expenses
2,144
Depreciation and depletion
3,350
1,015
2,531
2,580
1,141
10,836
Taxes other than income
1,188
1,742
1,298
5,000
Related income tax
2,093
4,728
6,068
3,852
17,718
Results of producing activities for consolidated
subsidiaries
2,696
2,158
2,323
4,330
2,650
14,773
Equity Companies
2010 - Revenue
Sales to third parties
1,012
-
5,050
-
12,682
-
18,744
Transfers
-
-
3,817
-
4,752
1,879
-
5,118
-
16,499
-
23,496
Production costs excluding taxes
-
-
-
1,095
Exploration expenses
-
-
-
Depreciation and depletion
-
-
-
Taxes other than income
-
2,515
-
3,844
-
6,391
Related income tax
-
-
-
5,295
-
6,110
Results of producing activities for equity companies
1,205
-
1,287
-
6,583
-
9,075
Total results of operations
3,901
2,158
3,610
4,330
9,233
23,848
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $10,643 million less at year-end 2012 and $6,651 million less at year-end 2011 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 have been included in the capitalized costs for 2012 and 2011 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, 2012
Property (acreage) costs
- Proved
12,081
3,911
1,610
19,645
- Unproved
25,769
1,456
28,616
Total property costs
37,850
5,367
1,304
2,320
1,133
48,261
Producing assets
70,603
21,947
44,068
37,921
23,230
6,910
204,679
Incomplete construction
4,840
18,726
1,589
5,070
12,654
5,988
48,867
Total capitalized costs
113,293
46,040
45,944
44,295
38,204
14,031
301,807
Accumulated depreciation and depletion
36,346
17,357
34,267
21,285
16,599
4,801
130,655
Net capitalized costs for consolidated subsidiaries
76,947
28,683
11,677
23,010
21,605
9,230
171,152
Equity Companies
As of December 31, 2012
Property (acreage) costs
- Proved
-
-
-
-
- Unproved
-
-
-
-
-
Total property costs
-
-
-
-
Producing assets
4,216
-
5,736
-
8,169
-
18,121
Incomplete construction
-
-
-
1,244
Total capitalized costs
4,635
-
5,859
-
8,991
-
19,485
Accumulated depreciation and depletion
1,447
-
4,494
-
3,744
-
9,685
Net capitalized costs for equity companies
3,188
-
1,365
-
5,247
-
9,800
Consolidated Subsidiaries
As of December 31, 2011
Property (acreage) costs
- Proved
10,969
3,837
1,567
18,342
- Unproved
25,398
1,402
28,180
Total property costs
36,367
5,239
1,349
2,322
1,082
46,522
Producing assets
65,941
20,393
40,646
32,059
22,675
6,035
187,749
Incomplete construction
4,652
12,385
9,831
9,922
4,131
41,885
Total capitalized costs
106,960
38,017
41,773
43,239
34,919
11,248
276,156
Accumulated depreciation and depletion
33,037
16,296
31,706
18,449
14,960
4,384
118,832
Net capitalized costs for consolidated subsidiaries
73,923
21,721
10,067
24,790
19,959
6,864
157,324
Equity Companies
As of December 31, 2011
Property (acreage) costs
- Proved
-
-
-
-
- Unproved
-
-
-
-
-
Total property costs
-
-
-
-
Producing assets
3,510
-
5,383
-
8,155
-
17,048
Incomplete construction
-
-
-
Total capitalized costs
3,794
-
5,599
-
8,703
-
18,096
Accumulated depreciation and depletion
1,354
-
4,267
-
3,068
-
8,689
Net capitalized costs for equity companies
2,440
-
1,332
-
5,635
-
9,407
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 2012 were $31,146 million, up $392 million from 2011, due primarily to higher exploration and development costs partially offset by lower property acquisition costs. 2011 costs were $30,754 million, down $40,058 million from 2010, due primarily to the absence of the acquisition of XTO Energy Inc. Total equity company costs incurred in 2012 were $1,404 million, up $178 million from 2011, due primarily to higher development 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 2012
Consolidated Subsidiaries
Property acquisition costs
- Proved
-
-
- Unproved
1,717
-
1,861
Exploration costs
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
-
-
-
-
-
Exploration costs
-
-
-
-
Development costs
-
-
-
1,311
Total costs incurred for equity companies
-
-
-
1,404
During 2011
Consolidated Subsidiaries
Property acquisition costs
- Proved
-
-
-
-
- Unproved
2,685
-
-
-
3,409
Exploration costs
2,452
Development costs
8,166
5,478
1,899
4,316
2,969
1,710
24,538
Total costs incurred for consolidated subsidiaries
11,575
6,028
2,539
4,619
4,129
1,864
30,754
Equity Companies
Property acquisition costs
- Proved
-
-
-
-
-
-
-
- Unproved
-
-
-
-
-
Exploration costs
-
-
-
-
Development costs
-
-
-
1,152
Total costs incurred for equity companies
-
-
-
1,226
During 2010
Consolidated Subsidiaries
Property acquisition costs
- Proved
21,633
-
-
21,792
- Unproved
23,509
-
-
-
23,668
Exploration costs
2,993
Development costs
7,947
4,757
1,227
4,390
2,892
1,146
22,359
Total costs incurred for consolidated subsidiaries
53,779
5,420
1,841
4,846
3,552
1,374
70,812
Equity Companies
Property acquisition costs
- Proved
-
-
-
-
-
-
-
- Unproved
-
-
-
-
-
Exploration costs
-
-
-
Development costs
-
-
-
Total costs incurred for equity companies
-
-
-
Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2010, 2011, and 2012.
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 2012 that were associated with production sharing contract arrangements was 12 percent of liquids, 8 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.
In accordance with the Securities and Exchange Commission’s rules, bitumen extracted through mining activities and hydrocarbons from other non-traditional resources are reported as oil and gas reserves beginning in 2009.
The rules in 2009 adopted a reliable technology definition that permits reserves to be added based on technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated.
The changes between 2011 year-end proved reserves and 2012 year-end proved reserves reflect the extensions and discoveries in North America.
Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves
Crude Oil and Natural Gas Liquids
Bitumen
Synthetic Oil
United
Canada/
Australia/
Canada/
Canada/
States
S. Amer.
Europe
Africa
Asia
Oceania
Total
S. Amer.
S. Amer.
Total
(millions of barrels)
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2010
1,616
1,907
1,999
6,469
2,055
9,215
Revisions
Improved recovery
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
Sales
(19)
-
-
(2)
-
-
(21)
-
-
(21)
Extensions/discoveries
-
-
-
Production
(123)
(30)
(121)
(229)
(119)
(21)
(643)
(42)
(24)
(709)
December 31,
1,952
1,799
2,023
6,635
2,102
9,418
Proportional interest in proved reserves of
equity companies
January 1, 2010
-
-
2,050
-
2,436
-
-
2,436
Revisions
-
-
(30)
-
(10)
-
-
(10)
Improved recovery
-
-
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
-
-
Sales
-
-
-
-
-
-
-
-
-
-
Extensions/discoveries
-
-
-
-
-
-
-
Production
(25)
-
(2)
-
(147)
-
(174)
-
-
(174)
December 31,
-
-
1,873
-
2,255
-
-
2,255
Total liquids proved reserves at
December 31,
2,303
1,799
3,896
8,890
2,102
11,673
Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen 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, 2011
1,679
1,589
1,839
5,773
2,102
9,418
Revisions
(55)
(4)
Improved recovery
-
-
-
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Sales
(3)
(11)
(24)
-
-
-
(38)
(14)
-
-
(52)
Extensions/discoveries
-
-
-
1,129
Production
(102)
(19)
(80)
(179)
(120)
(13)
(513)
(81)
(44)
(24)
(662)
December 31,
1,660
1,463
1,721
5,449
3,106
10,113
Proportional interest in proved
reserves of equity companies
January 1, 2011
-
-
1,394
-
1,775
-
-
2,255
Revisions
-
-
-
(21)
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
-
-
-
Sales
(2)
-
-
-
-
-
(2)
-
-
-
(2)
Extensions/discoveries
-
-
-
-
-
-
-
Production
(24)
-
(2)
-
(130)
-
(156)
(25)
-
-
(181)
December 31,
-
-
1,255
-
1,632
-
-
2,115
Total liquids proved reserves
at December 31,
2,008
1,463
2,976
7,081
1,388
3,106
12,228
Net proved developed and
undeveloped reserves of
consolidated subsidiaries
January 1, 2012
1,660
1,463
1,721
5,449
3,106
10,113
Revisions
(10)
(29)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
Sales
(15)
(1)
(8)
(58)
-
-
(82)
(4)
-
-
(86)
Extensions/discoveries
-
-
Production
(100)
(18)
(62)
(173)
(117)
(12)
(482)
(73)
(45)
(25)
(625)
December 31,
1,905
1,293
1,604
5,524
1,031
3,560
10,714
Proportional interest in proved
reserves of equity companies
January 1, 2012
-
-
1,255
-
1,632
-
-
2,115
Revisions
(2)
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
-
-
-
Sales
-
-
-
-
-
-
-
-
-
-
-
Extensions/discoveries
-
-
-
-
-
-
-
-
-
-
-
Production
(22)
-
(2)
-
(126)
-
(150)
(24)
-
-
(174)
December 31,
-
-
1,260
-
1,628
-
-
2,102
Total liquids proved reserves
at December 31,
2,245
1,293
2,864
7,152
1,505
3,560
12,816
(1) Includes total proved reserves attributable to Imperial Oil Limited of 10 million barrels in 2011 and 9 million barrels in 2012, as well as proved developed reserves of 10 million barrels in 2011 and 9 million barrels in 2012, in which there is a 30.4 percent noncontrolling interest.
Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen 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,
Consolidated subsidiaries
1,478
1,055
1,306
4,472
5,672
Equity companies
-
-
1,623
-
1,915
-
-
1,915
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
2,163
1,583
-
3,746
Equity companies
-
-
-
-
-
Total liquids proved reserves at
December 31,
2,303
1,799
3,896
8,890
2,102
11,673
Proved developed reserves, as of
December 31,
Consolidated subsidiaries
1,452
1,050
1,160
4,199
5,371
Equity companies
-
-
1,457
-
1,755
-
-
1,755
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
2,155
2,587
-
4,742
Equity companies
-
-
-
-
-
Total liquids proved reserves at
December 31,
2,372
1,675
3,620
8,469
3,106
12,228
Proved developed reserves, as of
December 31,
Consolidated subsidiaries
1,489
1,004
1,080
4,081
5,223
Equity companies
-
-
1,423
-
1,715
-
-
1,715
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
2,474
3,017
-
5,491
Equity companies
-
-
-
-
-
-
Total liquids proved reserves at
December 31,
2,758
1,501
3,488
8,657
(4)
3,560
12,816
(1) Includes total proved reserves attributable to Imperial Oil Limited of 57 million barrels in 2010, 55 million barrels in 2011 and 53 million barrels in 2012, as well as proved developed reserves of 56 million barrels in 2010, 55 million barrels in 2011 and 52 million barrels in 2012, and in addition, proved undeveloped reserves of 1 million barrels in both 2010 and 2012, in which there is a 30.4 percent noncontrolling interest.
(2) Includes total proved reserves attributable to Imperial Oil Limited of 1,715 million barrels in 2010, 2,413 million barrels in 2011 and 2,841 million barrels in 2012, as well as proved developed reserves of 519 million barrels in 2010, 519 million barrels in 2011 and 543 million barrels in 2012, and in addition, proved undeveloped reserves of 1,196 million barrels in 2010, 1,894 million barrels in 2011 and 2,298 million barrels in 2012, in which there is a 30.4 percent noncontrolling interest.
(3) Includes total proved reserves attributable to Imperial Oil Limited of 681 million barrels in 2010, 653 million barrels in 2011 and 599 million barrels in 2012, as well as proved developed reserves of 681 million barrels in 2010, 653 million barrels in 2011 and 599 million barrels in 2012, in which there is a 30.4 percent noncontrolling interest.
(4) See previous page 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 2012 Form 10-K.
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, 2010
11,688
1,368
4,723
8,303
7,440
34,442
14,955
Revisions
(26)
(333)
Improved recovery
-
-
-
-
-
-
-
Purchases
12,774
-
-
-
-
12,789
2,510
Sales
(104)
(2)
-
-
-
-
(106)
(38)
Extensions/discoveries
1,861
1,964
Production
(1,057)
(234)
(719)
(43)
(735)
(132)
(2,920)
(1,196)
December 31,
25,994
1,258
4,042
7,260
7,351
46,813
17,220
Proportional interest in proved reserves
of equity companies
January 1, 2010
-
11,450
-
22,001
-
33,565
8,030
Revisions
-
(4)
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Sales
-
-
-
-
-
-
-
-
Extensions/discoveries
-
-
-
-
-
Production
(5)
-
(724)
-
(1,093)
-
(1,822)
(478)
December 31,
-
10,746
-
21,139
-
32,002
7,589
Total proved reserves at December 31, 2010
26,111
1,258
14,788
28,399
7,351
78,815
24,809
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2011
25,994
1,258
4,042
7,260
7,351
46,813
17,220
Revisions
(236)
(231)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
Sales
(32)
(347)
(140)
-
-
-
(519)
(138)
Extensions/discoveries
1,779
-
-
2,042
1,469
Production
(1,554)
(173)
(655)
(39)
(750)
(132)
(3,303)
(1,213)
December 31,
26,254
3,586
6,471
7,247
45,375
17,676
Proportional interest in proved reserves
of equity companies
January 1, 2011
-
10,746
-
21,139
-
32,002
7,589
Revisions
-
-
(29)
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Sales
(1)
-
(3)
-
-
-
(4)
(3)
Extensions/discoveries
-
-
-
-
Production
(5)
-
(640)
-
(1,171)
-
(1,816)
(484)
December 31,
-
10,169
-
20,566
-
30,847
7,256
Total proved reserves at December 31, 2011
26,366
13,755
27,037
7,247
76,222
24,932
(See footnotes on next page)
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, 2012
26,254
3,586
6,471
7,247
45,375
17,676
Revisions
(2,888)
(106)
(2,191)
(39)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
Sales
(181)
(20)
(140)
(12)
-
-
(353)
(145)
Extensions/discoveries
4,045
-
-
4,383
1,490
Production
(1,518)
(153)
(555)
(43)
(579)
(144)
(2,992)
(1,124)
December 31,
26,215
3,249
5,845
7,568
44,731
18,169
Proportional interest in proved reserves
of equity companies
January 1, 2012
-
10,169
-
20,566
-
30,847
7,256
Revisions
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Sales
-
-
-
-
-
-
-
-
Extensions/discoveries
-
-
-
-
-
-
-
-
Production
(6)
-
(651)
-
(1,148)
-
(1,805)
(475)
December 31,
-
9,535
-
19,670
-
29,360
6,995
Total proved reserves at December 31, 2012
26,370
12,784
25,515
7,568
74,091
25,164
(1) Includes total proved reserves attributable to Imperial Oil Limited of 576 billion cubic feet in 2010, 422 billion cubic feet in 2011 and 488 billion cubic feet in 2012, as well as proved developed reserves of 507 billion cubic feet in 2010, 360 billion cubic feet in 2011 and 374 billion cubic feet in 2012, and in addition, proved undeveloped reserves of 69 billion cubic feet in 2010, 62 billion cubic feet in 2011 and 114 billion cubic feet in 2012, 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.
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,
Consolidated subsidiaries
15,344
1,077
3,516
6,593
1,174
28,415
10,408
Equity companies
-
8,167
-
20,494
-
28,758
6,708
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
10,650
6,177
18,398
6,812
Equity companies
-
2,579
-
-
3,244
Total proved reserves at December 31, 2010
26,111
1,258
14,788
28,399
7,351
78,815
24,809
Proved developed reserves, as of
December 31,
Consolidated subsidiaries
15,450
3,041
5,762
1,070
26,834
9,843
Equity companies
-
7,588
-
19,305
-
26,976
6,251
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
10,804
6,177
18,541
7,833
Equity companies
-
2,581
-
1,261
-
3,871
1,005
Total proved reserves at December 31, 2011
26,366
13,755
27,037
7,247
76,222
24,932
Proved developed reserves, as of
December 31,
Consolidated subsidiaries
14,471
2,526
5,150
1,012
24,643
9,330
Equity companies
-
7,057
-
18,431
-
25,614
5,984
Proved undeveloped reserves, as of
December 31,
Consolidated subsidiaries
11,744
6,556
20,088
8,839
Equity companies
-
2,478
-
1,239
-
3,746
1,011
Total proved reserves at December 31, 2012
26,370
12,784
25,515
7,568
74,091
25,164
(See footnotes on previous page)
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, 2010
Future cash inflows from sales of oil and gas
221,298
184,671
60,086
137,476
156,337
55,087
814,955
Future production costs
76,992
69,765
15,246
31,189
36,318
16,347
245,857
Future development costs
28,905
22,130
12,155
15,170
13,716
11,652
103,728
Future income tax expenses
44,128
21,798
21,736
46,145
59,477
9,591
202,875
Future net cash flows
71,273
70,978
10,949
44,972
46,826
17,497
262,495
Effect of discounting net cash flows at 10%
39,545
45,607
2,765
18,046
28,883
13,411
148,257
Discounted future net cash flows
31,728
25,371
8,184
26,926
17,943
4,086
114,238
Equity Companies
As of December 31, 2010
Future cash inflows from sales of oil and gas
26,110
-
73,222
-
232,334
-
331,666
Future production costs
6,369
-
49,010
-
73,508
-
128,887
Future development costs
2,883
-
2,719
-
2,523
-
8,125
Future income tax expenses
-
-
8,348
-
57,041
-
65,389
Future net cash flows
16,858
-
13,145
-
99,262
-
129,265
Effect of discounting net cash flows at 10%
9,612
-
6,857
-
51,512
-
67,981
Discounted future net cash flows
7,246
-
6,288
-
47,750
-
61,284
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows
38,974
25,371
14,472
26,926
65,693
4,086
175,522
(1) Includes discounted future net cash flows attributable to Imperial Oil Limited of $19,834 million in 2010, in which there is a 30.4 percent noncontrolling interest.
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, 2011
Future cash inflows from sales of oil and gas
264,991
280,991
71,847
179,337
203,007
86,456
1,086,629
Future production costs
105,391
98,135
15,045
36,309
43,442
23,381
321,703
Future development costs
31,452
35,121
11,987
15,384
16,010
10,052
120,006
Future income tax expenses
53,507
34,542
32,004
67,256
79,975
17,287
284,571
Future net cash flows
74,641
113,193
12,811
60,388
63,580
35,736
360,349
Effect of discounting net cash flows at 10%
42,309
79,303
3,525
22,029
38,066
22,873
208,105
Discounted future net cash flows
32,332
33,890
9,286
38,359
25,514
12,863
152,244
Equity Companies
As of December 31, 2011
Future cash inflows from sales of oil and gas
37,398
-
88,417
-
324,283
-
450,098
Future production costs
6,862
-
62,377
-
104,040
-
173,279
Future development costs
3,072
-
2,701
-
3,636
-
9,409
Future income tax expenses
-
-
9,035
-
76,825
-
85,860
Future net cash flows
27,464
-
14,304
-
139,782
-
181,550
Effect of discounting net cash flows at 10%
15,941
-
7,131
-
71,918
-
94,990
Discounted future net cash flows
11,523
-
7,173
-
67,864
-
86,560
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows
43,855
33,890
16,459
38,359
93,378
12,863
238,804
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 $27,568 million in 2011 and $24,690 million in 2012, in which there is a 30.4 percent noncontrolling interest.
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests
Total
Share of
Consolidated
Consolidated
Equity Method
and Equity
Subsidiaries
Investees
Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2009
65,846
49,310
115,156
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases less related costs
20,093
20,303
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
(46,078)
(16,050)
(62,128)
Development costs incurred during the year
20,975
21,818
Net change in prices, lifting and development costs
61,612
23,135
84,747
Revisions of previous reserves estimates
14,770
3,605
18,375
Accretion of discount
10,399
5,775
16,174
Net change in income taxes
(33,379)
(5,544)
(38,923)
Total change in the standardized measure during the year
48,392
11,974
60,366
Discounted future net cash flows as of December 31, 2010
114,238
61,284
175,522
Consolidated and Equity Interests
Total
Share of
Consolidated
Consolidated
Equity Method
and Equity
Subsidiaries
Investees
Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2010
114,238
61,284
175,522
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases less related costs
6,608
6,917
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
(58,308)
(22,402)
(80,710)
Development costs incurred during the year
22,843
1,153
23,996
Net change in prices, lifting and development costs
79,435
46,304
125,739
Revisions of previous reserves estimates
10,462
3,127
13,589
Accretion of discount
16,802
7,196
23,998
Net change in income taxes
(39,836)
(10,411)
(50,247)
Total change in the standardized measure during the year
38,006
25,276
63,282
Discounted future net cash flows as of December 31, 2011
152,244
86,560
238,804
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests (continued)
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
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
12,802
Total change in the standardized measure during the year
(14,695)
(14,017)
Discounted future net cash flows as of December 31, 2012
137,549
87,238
224,787
OPERATING
SUMMARY (unaudited)
Production of crude oil, natural gas liquids, synthetic oil and bitumen
Net production
(thousands of barrels daily)
United States
Canada/South America
Europe
Africa
Asia
Australia/Oceania
Worldwide
2,185
2,312
2,422
2,387
2,405
Natural gas production available for sale
Net production
(millions of cubic feet daily)
United States
3,822
3,917
2,596
1,275
1,246
Canada/South America
Europe
3,220
3,448
3,836
3,689
3,949
Africa
Asia
4,538
5,047
4,801
3,332
2,870
Australia/Oceania
Worldwide
12,322
13,162
12,148
9,273
9,095
(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)
4,239
4,506
4,447
3,932
3,921
Refinery throughput
(thousands of barrels daily)
United States
1,816
1,784
1,753
1,767
1,702
Canada
Europe
1,504
1,528
1,538
1,548
1,601
Asia Pacific
1,180
1,249
1,328
1,352
Other Non-U.S.
Worldwide
5,014
5,214
5,253
5,350
5,416
Petroleum product sales (2)
United States
2,569
2,530
2,511
2,523
2,540
Canada
Europe
1,571
1,596
1,611
1,625
1,712
Asia Pacific and other Eastern Hemisphere
1,381
1,556
1,562
1,588
1,646
Latin America
Worldwide
6,174
6,413
6,414
6,428
6,761
Gasoline, naphthas
2,489
2,541
2,611
2,573
2,654
Heating oils, kerosene, diesel oils
1,947
2,019
1,951
2,013
2,096
Aviation fuels
Heavy fuels
Specialty petroleum products
Worldwide
6,174
6,413
6,414
6,428
6,761
Chemical prime product sales
(thousands of metric tons)
United States
9,381
9,250
9,815
9,649
9,526
Non-U.S.
14,776
15,756
16,076
15,176
15,456
Worldwide
24,157
25,006
25,891
24,825
24,982
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.
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 27, 2013
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 27, 2013.
/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
/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/ EDWARD E. WHITACRE, JR.
(Edward E. Whitacre, Jr.)
Director
/s/ ANDREW P. SWIGER
(Andrew P. Swiger)
Senior Vice President
(Principal Financial Officer)
/s/ PATRICK T. MULVA
(Patrick T. Mulva)
Vice President and Controller
(Principal Accounting Officer)
INDEX TO EXHIBITS
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.*
10(iii)(a.2)
Form of restricted stock agreement with executive officers (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)(b.1)
Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.3 to the Registrant’s Report on Form 8-K on December 1, 2009).*
10(iii)(b.2)
Form of Earnings Bonus Unit instrument granted to executive officers (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 28, 2012).*
10(iii)(c.1)
ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant’s Annual Report on Form 10-K for 2011).*
10(iii)(c.2)
ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Annual Report on Form 10-K for 2011).*
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 2011).*
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 Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).*
10(iii)(f.2)
Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).*
10(iii)(f.3)
Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2009).*
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).*
Computation of ratio of earnings to fixed charges.
Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2008).
Subsidiaries of the registrant.
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.
INDEX TO EXHIBITS -
(continued)
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.
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.

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Stock Performance Metrics:
Return: 0.01152408309280872
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return