2012

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

or

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

NEW JERSEY

13-5409005

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)

 

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

 

 

 

Title of Each Class

Name of Each Exchange

on Which Registered

Common Stock, without par value (4,480,449,635 shares outstanding at January 31, 2013)

New York Stock  Exchange

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   þ    No    

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

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

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

Large accelerated filer  þ             Accelerated filer  

Non-accelerated filer              Smaller reporting company  

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $85.57 on the New York Stock Exchange composite tape, was in excess of $394 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2013 Annual Meeting of Shareholders (Part III)

 

 

 

     

 


 

 

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012

TABLE OF CONTENTS

 

 

 

PART I

 

 

 

Item 1.

Business

           1 

 

 

 

Item 1A.

Risk Factors

           2 

 

 

 

Item 1B.

Unresolved Staff Comments

           4 

 

 

 

Item 2.

Properties

           5 

 

 

 

Item 3.

Legal Proceedings

         26 

 

 

 

Item 4.

Mine Safety Disclosures

         26 

 

 

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

         27 

 

PART II

 

 

 

Item 5.

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

         30 

 

 

 

Item 6.

Selected Financial Data

         30 

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

         30 

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

         30 

 

 

 

Item 8.

Financial Statements and Supplementary Data

         31 

 

 

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

         31 

 

 

 

Item 9A.

Controls and Procedures

         31 

 

 

 

Item 9B.

Other Information

         31 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

         32  

 

 

 

Item 11.

Executive Compensation

         32  

 

 

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

         32  

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

         33  

 

 

 

Item 14.

Principal Accounting Fees and Services

         33  

 

PART IV

 

 

 

Item 15.

Exhibits, Financial Statement Schedules

         33  

 

 

Financial Section

         34  

 

 

Signatures

      114  

 

 

Index to Exhibits

      116  

 

 

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

 

 

 

Exhibits 31 and 32 — Certifications

 

 


 

 

PART I

ITEM 1.       BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. 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 “Item 1A–Risk Factors” and “Item 2–Properties” in this report.

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

 

1 

 


 

 

ITEM 1A.  RISK FACTORS

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

Supply and Demand

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

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

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

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

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

Government and Political Factors

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

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

Restrictions on doing business. 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.

2 

 


 

 

 

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

  

·

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

·

price controls;

·   

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

·

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

·

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

·

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

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

We also may be adversely affected by the outcome of litigation 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.

3 

 


 

 

 

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.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

4 

 


 

 

Item 2.       Properties

Information with regard to oil and gas producing activities follows:

 

1. Disclosure of Reserves

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

261 

14,471 

3,901 

 

 

 

Canada/South America (1) 

108 

16 

543 

599 

670 

1,378 

 

 

 

Europe

230 

38 

2,526 

689 

 

 

 

Africa

817 

187 

814 

1,140 

 

 

 

Asia

922 

158 

5,150 

1,938 

 

 

 

Australia/Oceania

63 

53 

1,012 

284 

 

 

 

 

Total Consolidated

3,368 

713 

543 

599 

24,643 

9,330 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

258 

126 

285 

 

 

 

Europe

28 

7,057 

1,204 

 

 

 

Asia

1,009 

414 

18,431 

4,495 

 

 

 

 

Total Equity Company

1,295 

420 

25,614 

5,984 

 

 

 

 

Total Developed

4,663 

1,133 

543 

599 

50,257 

15,314 

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

677 

244 

11,744 

2,878 

 

 

 

Canada/South America (1) 

162 

3,017 

255 

3,222 

 

 

 

Europe

59 

18 

723 

198 

 

 

 

Africa

476 

21 

115 

516 

 

 

 

Asia

682 

695 

798 

 

 

 

Australia/Oceania

100 

34 

6,556 

1,227 

 

 

 

 

Total Consolidated

2,156 

318 

3,017 

20,088 

8,839 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

82 

29 

89 

 

 

 

Europe

2,478 

413 

 

 

 

Asia

251 

52 

1,239 

509 

 

 

 

 

Total Equity Company

333 

54 

3,746 

1,011 

 

 

 

 

Total Undeveloped

2,489 

372 

3,017 

23,834 

9,850 

Total Proved Reserves

7,152 

1,505 

3,560 

599 

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.

5 

 


 

 

 

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

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the 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

6 

 


 

 

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.

7 

 


 

 

 

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

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area for the last three years.

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

(thousands of barrels daily)

Crude oil and natural gas liquids production

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

355 

 

357 

 

339 

 

 

Canada/South America (1) 

 

59 

 

65 

 

81 

 

 

Europe

 

203 

 

265 

 

330 

 

 

Africa

 

487 

 

508 

 

628 

 

 

Asia

 

362 

 

383 

 

326 

 

 

Australia/Oceania

 

50 

 

51 

 

58 

 

 

 

Total Consolidated Subsidiaries

 

1,516 

 

1,629 

 

1,762 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

63 

 

66 

 

69 

 

 

Europe

 

 

 

 

 

Asia

 

410 

 

425 

 

404 

 

 

 

Total Equity Companies

 

477 

 

496 

 

478 

 

 

 

 

 

 

 

 

 

 

Total crude oil and natural gas liquids production

 

1,993 

 

2,125 

 

2,240 

 

 

 

 

 

 

 

 

 

 

Bitumen production

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

Canada/South America

 

123 

 

120 

 

115 

 

 

 

 

 

 

 

 

 

 

Synthetic oil production

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

Canada/South America

 

69 

 

67 

 

67 

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) 

 

362 

 

412 

 

569 

 

 

Europe

 

1,446 

 

1,701 

 

1,859 

 

 

Africa

 

17 

 

 

14 

 

 

Asia

 

1,445 

 

1,879 

 

1,847 

 

 

Australia/Oceania

 

363 

 

331 

 

332 

 

 

 

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.

8 

 


 

 

 

B. Production Prices and Production Costs

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

 

 

 

 

 

 

United

 

Canada/

 

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

S. America

Europe

 

Africa

 

Asia

 

Oceania

 

Total

During 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 

9 

 


 

 

 

 

 

 

 

 

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.

10 

 


 

 

 

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

 

 

 

 

 

Net Productive Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

 

12 

 

17 

 

 

Canada/South America

 

 

 

12 

 

 

Europe

 

 

 

 

 

Africa

 

 

 

 

 

Asia

 

 

 

 

 

Australia/Oceania

 

 

 

 

 

 

Total Consolidated Subsidiaries

 

15 

 

23 

 

35 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

 

 

 

 

Europe

 

 

 

 

 

Asia

 

 

 

 

 

 

Total Equity Companies

 

 

 

Total productive exploratory wells drilled

 

16 

 

25 

 

37 

 

 

 

 

 

 

 

 

 

 

Net Dry Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

 

 

 

 

Canada/South America

 

 

 

 

 

Europe

 

 

 

 

 

Africa

 

 

 

 

 

Asia

 

 

 

 

 

Australia/Oceania

 

 

 

 

 

 

Total Consolidated Subsidiaries

 

 

11 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

 

 

 

 

Europe

 

 

 

 

 

Asia

 

 

 

 

 

 

Total Equity Companies

 

 

 

Total dry exploratory wells drilled

 

 

11 

 

11 

 


 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

 

 

 

 

 

Net Productive Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

867 

 

1,069 

 

604 

 

 

Canada/South America

 

73 

 

154 

 

229 

 

 

Europe

 

10 

 

 

11 

 

 

Africa

 

39 

 

44 

 

60 

 

 

Asia

 

28 

 

30 

 

 

 

Australia/Oceania

 

 

 

 

 

 

Total Consolidated Subsidiaries

 

1,017 

 

1,304 

 

913 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

282 

 

236 

 

282 

 

 

Europe

 

 

10 

 

 

 

Asia

 

 

 

 

 

 

Total Equity Companies

 

293 

 

250 

 

287 

Total productive development wells drilled

 

1,310 

 

1,554 

 

1,200 

 

 

 

 

 

 

 

 

 

 

Net Dry Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

 

14 

 

 

 

Canada/South America

 

 

 

 

 

Europe

 

 

 

 

 

Africa

 

 

 

 

 

Asia

 

 

 

 

 

Australia/Oceania

 

 

 

 

 

 

Total Consolidated Subsidiaries

 

 

16 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

 

 

 

 

Europe

 

 

 

 

 

Asia

 

 

 

 

 

 

Total Equity Companies

 

 

 

Total dry development wells drilled

 

 

16 

 

 

 

 

 

 

 

 

 

 

 

 

Total number of net wells drilled

 

1,342 

 

1,606 

 

1,249 

12 

 


 

 

 

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

Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 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 

 

503 

 

1,276 

 

527 

 

 

Canada/South America

138 

 

118 

 

83 

 

69 

 

 

Europe

26 

 

10 

 

26 

 

 

 

Africa

33 

 

10 

 

34 

 

11 

 

 

Asia

108 

 

61 

 

102 

 

63 

 

 

Australia/Oceania

23 

 

 

 

 

 

 

Total Consolidated Subsidiaries

1,427 

 

708 

 

1,530 

 

680 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

17 

 

 

 

 

 

Europe

 

 

13 

 

 

 

Asia

19 

 

 

32 

 

 

 

 

Total Equity Companies

45 

 

 

47 

 

Total gross and net wells drilling

1,472 

 

717 

 

1,577 

 

687 

 

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.  

13 

 


 

 

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.

14 

 


 

 

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.

15 

 


 

 

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.

16 

 


 

 

 

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 

346 

622 

258 

 

1,340 

357 

647 

265 

 

 

Africa

1,231 

491 

11 

 

1,167 

465 

12 

 

 

Asia

792 

370 

204 

150 

 

783 

399 

224 

178 

 

 

Australia/Oceania

676 

152 

40 

20 

 

712 

171 

32 

16 

 

 

 

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 

120 

 

11,068 

5,200 

 

 

Europe

71 

27 

585 

185 

 

61 

23 

593 

191 

 

 

Asia

1,200 

129 

121 

29 

 

894 

100 

121 

30 

 

 

 

Total Equity Companies

14,048 

5,442 

2,844 

334 

 

12,023 

5,323 

715 

221 

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.

 

 

17 

 


 

 

 

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 

 

780 

 

1,850 

 

700 

 

 

Asia

1,322 

 

525 

 

1,326 

 

590 

 

 

Australia/Oceania

2,018 

 

719 

 

1,955 

 

719 

 

 

 

Total Consolidated Subsidiaries

29,816 

 

15,643 

 

30,519 

 

15,735 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

496 

 

202 

 

131 

 

55 

 

 

Europe

4,344 

 

1,357 

 

4,343 

 

1,357 

 

 

Asia

5,731 

 

640 

 

5,732 

 

640 

 

 

 

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

351 

 

108 

 

302 

 

97 

 

 

Europe

 - 

 

 - 

 

 - 

 

 - 

 

 

Asia

73 

 

 

72 

 

 

 

 

Total Equity Companies

424 

 

113 

 

374 

 

102 

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.

18 

 


 

 

 

D. Summary of Acreage Terms

UNITED STATES

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

CANADA / SOUTH AMERICA

Canada

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

Argentina

The federal 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.

19 

 


 

 

United Kingdom

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

AFRICA

Angola

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

Chad

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

Equatorial Guinea

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for 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.

20 

 


 

 

 

ASIA

Azerbaijan

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

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

Indonesia

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract (PSC), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. In 2012, Indonesia’s Constitutional Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but stated that all existing PSCs signed with BPMIGAS should remain in force until their expiry, and the functions and duties previously performed by BPMIGAS are to be carried out by the relevant Ministry of the Government of Indonesia until the promulgation of a new oil and gas law. 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.

21 

 


 

 

 

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.

22 

 


 

 

 

Information with regard to the Downstream segment follows:

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

Refining Capacity At Year-End 2012 (1) 

 

 

 

 

ExxonMobil

ExxonMobil

 

 

 

 

Share  KBD (2) 

Interest %

United States

 

 

 

 

 

 

Torrance

California

150 

 

100 

 

 

Joliet

Illinois

238 

 

100 

 

 

Baton Rouge

Louisiana

502 

 

100 

 

 

Baytown

Texas

561 

 

100 

 

 

Beaumont

Texas

345 

 

100 

 

 

Other (2 refineries)

 

155 

 

 

 

 

 

 Total United States

 

1,951 

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

Strathcona

Alberta

189 

 

69.6 

 

 

Dartmouth

Nova Scotia

85 

 

69.6 

 

 

Nanticoke

Ontario

113 

 

69.6 

 

 

Sarnia

Ontario

119 

 

69.6 

 

 

 

Total Canada

 

506 

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

Antwerp

Belgium

307 

 

100 

 

 

Fos-sur-Mer

France

131 

 

82.9 

 

 

Gravenchon

France

235 

 

82.9 

 

 

Karlsruhe

Germany

78 

 

25 

 

 

Augusta

Italy

198 

 

100 

 

 

Trecate

Italy

126 

 

75.5 

 

 

Rotterdam

Netherlands

191 

 

100 

 

 

Slagen

Norway

116 

 

100 

 

 

Fawley

United Kingdom

258 

 

100 

 

 

 

Total Europe

 

1,640 

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

Jurong/PAC

Singapore

592 

 

100 

 

 

Sriracha

Thailand

170 

 

66 

 

 

Other (7 refineries)

 

299 

 

 

 

 

 

Total Asia Pacific

 

1,061 

 

 

 

 

 

 

 

 

 

 

 

Other Non-U.S.

 

 

 

 

 

 

Yanbu

Saudi Arabia

200 

 

50 

 

 

Laffan

Qatar

15 

 

10 

 

 

Martinique

Martinique

 

14.5 

 

 

 

Total Other Non-U.S.

 

217 

 

 

 

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.

23 

 


 

 

 

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

115 

 

 

 

Distributors/resellers

8,921 

 

 

 

 

Total United States

9,036 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

Owned/leased

474 

 

 

 

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

689 

 

 

 

Distributors/resellers

256 

 

 

 

 

Total Asia Pacific

945 

 

 

 

 

 

 

 

 

Latin America

 

 

 

 

Owned/leased

156 

 

 

 

Distributors/resellers

757 

 

 

 

 

Total Latin America

913 

 

 

 

 

 

 

 

 

Middle East/Africa

 

 

 

 

Owned/leased

446 

 

 

 

Distributors/resellers

186 

 

 

 

 

Total Middle East/Africa

632 

 

 

 

 

 

 

 

 

Worldwide

 

 

 

 

Owned/leased

5,593 

 

 

 

Distributors/resellers

13,789 

 

 

 

 

Total Worldwide

19,382 

 

24 

 


 

 

 

Information with regard to the Chemical segment follows:

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

Chemical Complex Capacity At Year-End 2012 (1)(2)   

 

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil

 

 

 

 

Ethylene

Polyethylene

Polypropylene

Paraxylene

Interest %

North America

 

 

 

 

 

 

 

 

 

 

 

 

Baton Rouge

Louisiana

1.0 

 

1.3 

 

0.4 

 

 

100 

 

 

Baytown

Texas

2.2 

 

 

0.8 

 

0.6 

 

100 

 

 

Beaumont

Texas

0.9 

 

1.0 

 

 

0.3 

 

100 

 

 

Mont Belvieu

Texas

 

1.0 

 

 

 

100 

 

 

Sarnia

Ontario

0.3 

 

0.5 

 

 

 

69.6 

 

 

 

Total North America

 

4.4 

 

3.8 

 

1.2 

 

0.9 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

 

 

 

 

 

 

Antwerp

Belgium

 

0.4 

 

 

 

100 

 

 

Fife

United Kingdom

0.4 

 

 

 

 

50 

 

 

Meerhout

Belgium

 

0.5 

 

 

 

100 

 

 

Gravenchon

France

0.4 

 

0.4 

 

0.3 

 

 

100 

 

 

Rotterdam

Netherlands

 

 

 

0.7 

 

100 

 

 

 

Total Europe

 

0.8 

 

1.3 

 

0.3 

 

0.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Middle East

 

 

 

 

 

 

 

 

 

 

 

 

Al Jubail

Saudi Arabia

0.6 

 

0.6 

 

 

 

50 

 

 

Yanbu

Saudi Arabia

1.0 

 

0.7 

 

0.2 

 

 

50 

 

 

 

Total Middle East

 

1.6 

 

1.3 

 

0.2 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

 

 

 

 

 

 

Fujian

China

0.2 

 

0.2 

 

0.1 

 

0.2 

 

25 

 

 

Kawasaki

Japan

0.1 

 

 

 

 

22 

 

 

Singapore

Singapore

0.9 

 

1.9 

 

0.9 

 

0.9 

 

100 

 

 

Sriracha

Thailand

 

 

 

0.5 

 

66 

 

 

 

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. 

 

25 

 


 

 

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.

 

Item 4.       MINE SAFETY DISCLOSURES

Not applicable.

 

                                                                        _______________________ 

26 

 


 

 

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.

27 

 


 

 

 

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:  53

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, 2008

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.

28 

 


 

 

 

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:  49

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.

29 

 


 

 

PART II

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

Reference is made to the “Quarterly Information” portion of the Financial Section of this report.

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 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.

 

Item 6.       Selected Financial Data

 

 

 

Years Ended December 31,

 

 

2012 (1) 

 

2011 

 

2010 

 

2009 

 

2008 

 

 

(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.

 

 

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

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

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

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

 

30 

 


 

 

Item 8.       Financial Statements and Supplementary Data

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

·

Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 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 on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 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.

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.

31 

 


 

 

PART III

Item 10.     Directors, Executive Officers and Corporate Governance

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 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”.

 

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.

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.

32 

 


 

 

 

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

Incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 2013 Proxy Statement.

Item 14.     Principal Accounting Fees and Services

Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2013 Proxy Statement.

 

PART IV

Item 15.     Exhibits, Financial Statement Schedules

(a)      (1) and (2) Financial Statements:

           See Table of Contents of the Financial Section of this report.

(a)      (3) Exhibits:

           See Index to Exhibits of this report.

33 

 


 

 

FINANCIAL SECTION

 

 

TABLE OF CONTENTS

 

 

 

Business Profile

35

 

 

Financial Summary

36

 

 

Frequently Used Terms

37

 

 

Quarterly Information

39

 

 

Management’s Discussion and Analysis of Financial Condition

and Results of Operations

 

 

 

Functional Earnings

40

 

 

Forward-Looking Statements

41

 

 

Overview

41

 

 

Business Environment and Risk Assessment

41

 

 

Review of 2012 and 2011 Results

44

 

 

Liquidity and Capital Resources

47

 

 

Capital and Exploration Expenditures

52

 

 

Taxes

52

 

 

Environmental Matters

53

 

 

Market Risks, Inflation and Other Uncertainties

53

 

 

Critical Accounting Estimates

55

 

 

Management’s Report on Internal Control Over Financial Reporting

59

 

 

Report of Independent Registered Public Accounting Firm

60

 

 

Consolidated Financial Statements

 

 

 

Statement of Income

61

 

 

Statement of Comprehensive Income

62

 

 

Balance Sheet

63

 

 

Statement of Cash Flows

64

 

 

Statement of Changes in Equity

65

 

 

Notes to Consolidated Financial Statements

 

 

 

  1. Summary of Accounting Policies

66

 

 

  2. Accounting Changes

68

 

 

  3. Miscellaneous Financial Information

68

 

 

  4. Other Comprehensive Income Information

69

 

 

  5. Cash Flow Information

70

 

 

  6. Additional Working Capital Information

70

 

 

  7. Equity Company Information

71

 

 

  8. Investments, Advances and Long-Term Receivables

72

 

 

  9. Property, Plant and Equipment and Asset Retirement Obligations

72

 

 

10. Accounting for Suspended Exploratory Well Costs

74

 

 

11. Leased Facilities

76

 

 

12. Earnings Per Share

76

 

 

13. Financial Instruments and Derivatives

77

 

 

14. Long-Term Debt

78

 

 

15. Incentive Program

79

 

 

16. Litigation and Other Contingencies

81

 

 

17. Pension and Other Postretirement Benefits

83

 

 

18. Disclosures about Segments and Related Information

91

 

 

19. Income, Sales-Based and Other Taxes

94

 

 

20. Japan Restructuring

97

 

 

Supplemental Information on Oil and Gas Exploration and Production Activities

98

 

 

Operating Summary

113

 

34 

 


 

BUSINESS PROFILE

 

 

 

 

 

 

 

 

 

 

 

 

Return on

 

 

Capital and

 

 

 

 

Earnings After

 

Average Capital

 

Average Capital

 

 

Exploration

 

 

 

 

Income Taxes

 

Employed

 

Employed

 

 

Expenditures

Financial

 

2012 

 

2011 

 

2012 

 

2011 

 

2012 

 

2011 

 

 

2012 

 

2011 

 

 

 

 

(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 

 

 

634 

 

518 

 

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 

 

 

408 

 

290 

 

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)

 

 

 

 

35 

 

105 

 

 

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

2012 

 

2011 

 

 

 

 

2012 

 

2011 

 

 

(thousands of barrels daily)

 

 

 

(thousands of barrels daily)

Net liquids production

 

 

 

 

Refinery throughput

 

 

 

 

United States

418 

 

423 

 

 

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.

35 

 


 

FINANCIAL SUMMARY

 

 

 

 

 

2012 

 

2011 

 

2010 

 

2009 

 

2008 

 

 

(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

 

321 

 

(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 

 

847 

 

 

 

 

 

 

 

 

 

 

 

 

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.

36 

 


 

FREQUENTLY USED TERMS

 

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

Cash Flow From Operations and Asset Sales

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

 

Cash flow from operations and asset sales

 

2012 

 

2011 

 

2010 

 

 

 

(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

 

2012 

 

2011 

 

2010 

 

 

 

(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 

37 

 


 

FREQUENTLY USED TERMS

 

 

Return on Average Capital Employed

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

 

Return on average capital employed

 

2012 

 

2011 

 

2010 

 

 

 

 

 

(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

 

100 

 

116 

 

35 

 

 

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%

38 

 


 

QUARTERLY INFORMATION

 

 

 

 

 

2012 

 

2011 

 

 

 

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.

39 

 


 

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

 

 

FUNCTIONAL EARNINGS

 

2012 

 

2011 

 

2010 

 

 

 

 

(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 

 

770 

 

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.

40 

 


 

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

 

 

 

FORWARD-LOOKING STATEMENTS

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

The term “project” as used in this report 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

41 

 


 

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.

42 

 


 

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.

43 

 


 

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

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

(millions of dollars)

 

 

 

 

 

 

 

Earnings (U.S. GAAP)

 

 44,880 

 

 41,060 

 

 30,460 

 

2012

Earnings in 2012 of $44,880 million increased $3,820 million from 2011. 

 

2011

Earnings in 2011 of $41,060 million increased $10,600 million from 2010. 

 

Upstream

 

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(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 

 

2012

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

44 

 


 

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.

 

2011

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

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(millions of dollars)

Downstream

 

 

 

 

 

 

 

United States

 

3,575 

 

2,268 

 

770 

 

Non-U.S.

 

9,615 

 

2,191 

 

2,797 

 

 

Total

 

13,190 

 

4,459 

 

3,567 

 

2012

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.

 

2011

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.

 

45 

 


 

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

 

 

 

Chemical

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(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 

 

2012

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.

 

2011

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

 

 

 

 

2012 

 

2011 

 

2010 

 

 

(millions of dollars)

 

 

 

 

 

 

 

Corporate and financing

 

(2,103)

 

(2,221)

 

(2,117)

 

2012

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

 

2011

Corporate and financing expenses were $2,221 million, up $104 million from 2010.

46 

 


 

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

 

 

 

LIQUIDITY AND CAPITAL RESOURCES

 

 

 

 

 

 

 

 

 

 

 

Sources and Uses of Cash

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

(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

 

217 

 

(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

 

341 

 

404 

 

628 

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.

 

47 

 


 

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

 

 

Cash Flow from Operating Activities

 

2012

Cash provided by operating activities totaled $56.2 billion in 2012, $0.8 billion higher than 2011. The major source of funds was net income 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. 

 

2011

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

 

2012

Cash used in investment activities netted to $25.6 billion in 2012, $3.4 billion higher than 2011. Spending for property, plant and equipment of $34.3 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.

 

2011

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

 

2012

Cash used in financing activities was $33.9 billion in 2012, $5.6 billion higher than 2011. Dividend payments on common shares increased to $2.18 per 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.

  

2011

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

48 

 


 

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.

49 

 


 

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

 

 

 

 

 

2018 

 

 

 

 

Reference

 

 

 

2014-

 

and

 

 

Commitments

Number

 

2013 

 

2017 

 

Beyond

 

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

Long-term debt  (1) 

14 

 

 

2,885 

 

5,043 

 

7,928 

 

 – Due in one year  (2) 

 

1,025 

 

 

 

1,025 

Asset retirement obligations  (3) 

 

776 

 

3,334 

 

7,863 

 

11,973 

Pension and other postretirement obligations  (4) 

17 

 

2,401 

 

4,328 

 

19,475 

 

26,204 

Operating leases  (5) 

11 

 

2,254 

 

4,460 

 

1,467 

 

8,181 

Unconditional purchase obligations  (6) 

16 

 

184 

 

624 

 

319 

 

1,127 

Take-or-pay obligations  (7) 

 

 

2,673 

 

10,523 

 

13,013 

 

26,209 

Firm capital commitments  (8) 

 

 

19,609 

 

12,074 

 

836 

 

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.

50 

 


 

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.

 

 

 

2012 

 

2011 

 

2010 

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.

51 

 


 

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

 

 

 

CAPITAL AND EXPLORATION EXPENDITURES

 

 

 

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

 

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

634 

 

1,628 

 

2,262 

 

518 

 

1,602 

 

2,120 

Chemical

408 

 

1,010 

 

1,418 

 

290 

 

1,160 

 

1,450 

Other

35 

 

 

35 

 

105 

 

 

105 

 

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

 

 

 

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

(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 

 

2012

Income, sales-based and all other taxes and duties totaled $102.3 billion in 2012, a decrease of $5.8 billion or 5 percent from 2011. Income tax expense, 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.

 

2011

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.

52 

 


 

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

 

 

 

ENVIRONMENTAL MATTERS

 

Environmental Expenditures

 

 

 

 

 

 

 

2012 

 

2011 

 

 

 

(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) 

 

2012 

 

2011 

 

2010 

 

 

 

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.

53 

 


 

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.

54 

 


 

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.

55 

 


 

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.

 

56 

 


 

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

57 

 


 

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.

58 

 


 

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)

59 

 


 

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

60 

 


 

CONSOLIDATED STATEMENT OF INCOME

 

 

 

Note

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

Number

 

2012 

 

2011 

 

2010 

 

 

 

 

 

(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

 

 

327 

 

247 

 

259 

 

Sales-based taxes (1)

19 

 

32,409 

 

33,503 

 

28,547 

 

Other taxes and duties

19 

 

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

19 

 

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 

 

938 

Net income attributable to ExxonMobil

 

 

44,880 

 

41,060 

 

30,460 

 

 

 

 

 

 

 

 

 

 

Earnings per common share (dollars)

12 

 

9.70 

 

8.43 

 

6.24 

 

 

 

 

 

 

 

 

 

 

Earnings per common share - assuming dilution (dollars)

12 

 

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.

61 

 


 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

 

(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

 

 920 

 

(867)

 

1,034 

 

Adjustment for foreign exchange translation (gain)/loss

 

 

 

 

 

 

 

 

included in net income

 

(4,352)

 

 - 

 

 25 

 

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

 

 - 

 

28 

 

 184 

 

Realized (gain)/loss from settled cash flow hedges included in net income

 

 - 

 

(83)

 

(129)

 

 

Total other comprehensive income

 

(4,611)

 

(4,612)

 

993 

Comprehensive income including noncontrolling interests

 

43,070 

 

37,594 

 

32,391 

 

Comprehensive income attributable to noncontrolling interests

 

1,251 

 

834 

 

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.

62 

 


 

CONSOLIDATED BALANCE SHEET

 

 

 

 

Note

 

 

 

 

 

 

 

 

Reference

 

Dec. 31

 

Dec. 31

 

 

 

 

Number

 

2012 

 

2011 

 

 

 

 

 

 

(millions of dollars)

Assets

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

9,582 

 

12,664 

 

 

Cash and cash equivalents - restricted

 

 

341 

 

404 

 

 

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

14 

 

7,928 

 

9,322 

 

Postretirement benefits reserves

17 

 

25,267 

 

24,994 

 

Deferred income tax liabilities

19 

 

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

16 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

63 

 


 

CONSOLIDATED STATEMENT OF CASH FLOWS

 

 

 

 

 

Note

 

 

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

 

 

Number

 

2012 

 

2011 

 

2010 

 

 

 

 

 

 

 

(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 

 

142 

 

 (1,135) 

 

 

Postretirement benefits expense

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) net payments

 

 

(315)

 

544 

 

1,700 

 

 

Other long-term obligation provisions

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) payments

 

 

 1,643 

 

(151)

 

160 

 

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)

 

222 

 

913 

 

 

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

 

 

63 

 

224 

 

 (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 

 

155 

 

 

Net cash used in investing activities

 

 

(25,601)

 

(22,165)

 

(24,204)

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

Additions to long-term debt

 

 

995 

 

702 

 

1,143 

 

Reductions in long-term debt

 

 

(147)

 

(266)

 

(6,224)

 

Additions to short-term debt

 

 

958 

 

1,063 

 

598 

 

Reductions in short-term debt

 

 

(4,488)

 

(1,103)

 

(2,436)

 

Additions/(reductions) in debt with three months or less maturity

 

(226)

 

1,561 

 

709 

 

Cash dividends to ExxonMobil shareholders

 

 

(10,092)

 

(9,020)

 

(8,498)

 

Cash dividends to noncontrolling interests

 

 

(327)

 

(306)

 

(281)

 

Changes in noncontrolling interests

 

 

204 

 

(16)

 

(7)

 

Tax benefits related to stock-based awards

 

 

130 

 

260 

 

122 

 

Common stock acquired

 

 

(21,068)

 

(22,055)

 

(13,093)

 

Common stock sold

 

 

193 

 

924 

 

1,043 

 

 

Net cash used in financing activities

 

 

(33,868)

 

(28,256)

 

(26,924)

Effects of exchange rate changes on cash

 

 

217 

 

(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.

64 

 


 

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

 

751 

 

 - 

 

 - 

 

 - 

 

751 

 

 - 

 

751 

 

Tax benefits related to stock-based awards

 

280 

 

 - 

 

 - 

 

 - 

 

280 

 

 - 

 

280 

 

Other

 

(683)

 

 - 

 

 - 

 

 - 

 

(683)

 

 10 

 

(673)

 

Net income for the year

 

 - 

 

30,460 

 

 - 

 

 - 

 

30,460 

 

938 

 

31,398 

 

Dividends - common shares

 

 - 

 

(8,498)

 

 - 

 

 - 

 

(8,498)

 

(281)

 

(8,779)

 

Other comprehensive income

 

 - 

 

 - 

 

638 

 

 - 

 

638 

 

355 

 

993 

 

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

 

742 

 

 - 

 

 - 

 

 - 

 

742 

 

 - 

 

742 

 

Tax benefits related to stock-based awards

 

202 

 

 - 

 

 - 

 

 - 

 

202 

 

 - 

 

202 

 

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

 

806 

 

 - 

 

 - 

 

 - 

 

806 

 

 - 

 

806 

 

Tax benefits related to stock-based awards

 

178 

 

 - 

 

 - 

 

 - 

 

178 

 

 - 

 

178 

 

Other

 

(843)

 

 - 

 

 - 

 

 - 

 

(843)

 

(1,441)

 

(2,284)

 

Net income for the year

 

 - 

 

44,880 

 

 - 

 

 - 

 

44,880 

 

2,801 

 

47,681 

 

Dividends - common shares

 

 - 

 

(10,092)

 

 - 

 

 - 

 

(10,092)

 

(327)

 

(10,419)

 

Other comprehensive income

 

 - 

 

 - 

 

(3,061)

 

 - 

 

(3,061)

 

 (1,550) 

 

(4,611)

 

Acquisitions, at cost

 

 - 

 

 - 

 

 - 

 

(21,068)

 

(21,068)

 

(34)

 

(21,102)

 

Dispositions

 

 - 

 

 - 

 

 - 

 

667 

 

667 

 

 - 

 

667 

Balance as of December 31, 2012

 

9,653 

 

365,727 

 

 (12,184) 

 

(197,333)

 

165,863 

 

5,797 

 

171,660 

 

 

 

 

 

 

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

 

 - 

 

416 

 

416 

 

Other dispositions

 

 - 

 

35 

 

35 

Balance as of December 31, 2010

 

8,019 

 

(3,040)

 

4,979 

 

Acquisitions

 

 - 

 

(278)

 

(278)

 

Dispositions

 

 - 

 

33 

 

33 

Balance as of December 31, 2011

 

8,019 

 

(3,285)

 

4,734 

 

Acquisitions

 

 - 

 

(244)

 

(244)

 

Dispositions

 

 - 

 

12 

 

12 

Balance as of December 31, 2012

 

8,019 

 

(3,517)

 

4,502 

 

 

 

 

 

 

 

 

 

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

65 

 


 

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

66 

 


 

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.

67 

 


 

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:

 

 

 

 

2012 

 

2011 

 

 

 

    (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 

68 

 


 

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

584 

 

 

(1,014)

 

 

184 

 

 

(246)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

25 

 

 

988 

 

 

(129)

 

 

884 

 

Total change in accumulated other comprehensive income

609 

 

 

(26)

 

 

55 

 

 

638 

 

Balance as of December 31, 2010

5,011 

 

 

(9,889)

 

 

55 

 

 

(4,823)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2010

5,011 

 

 

(9,889)

 

 

55 

 

 

(4,823)

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(843)

 

 

(4,557)

 

 

28 

 

 

(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

842 

 

 

(3,402)

 

 

 - 

 

 

(2,560)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

(2,600)

 

 

2,099 

 

 

 - 

 

 

(501)

 

Total change in accumulated other comprehensive income

(1,758)

 

 

(1,303)

 

 

 - 

 

 

(3,061)

 

Balance as of December 31, 2012

2,410 

 

 

(14,594)

 

 

 - 

 

 

(12,184)

 

 

 

Income Tax (Expense)/Credit For

 

 

 

 

 

Components of Other Comprehensive Income

2012 

 

2011 

 

2010 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Foreign exchange translation adjustment

(236)

 

89 

 

(42)

Postretirement benefits reserves adjustment

 

 

 

 

 

 

Postretirement benefits reserves adjustment (excluding amortization)

1,619 

 

2,039 

 

689 

 

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

 - 

 

50 

 

79 

Total

157 

 

1,618 

 

(41)

69 

 


 

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.

 

 

 

2012 

 

2011 

 

2010 

 

 

(millions of dollars)

 

 

 

 

 

 

 

Cash payments for interest

 

555 

 

557 

 

703 

 

 

 

 

 

 

 

Cash payments for income taxes

 

24,349 

 

27,254 

 

18,941 

 

6. Additional Working Capital Information

 

 

 

 

Dec. 31

 

Dec. 31

 

 

 

 

2012 

 

2011 

 

 

 

 

(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

 

663 

 

1,237 

 

Commercial paper

 

1,963 

 

2,281 

 

Long-term debt due within one year

 

1,025 

 

3,431 

 

Other

 

 

762 

 

 

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.

70 

 


 

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.

 

 

 

 

2012 

 

2011 

 

2010 

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

48 

 

Chalmette Refining, LLC

50 

BEB Erdgas und Erdoel GmbH & Co. KG

50 

 

Fujian Refining & Petrochemical Co. Ltd.

25 

Cameroon Oil Transportation Company S.A.

41 

 

Saudi Aramco Mobil Refinery Company Ltd.

50 

Castle Peak Power Company Limited

60 

 

TonenGeneral Sekiyu K.K.

22 

Cross Timbers Energy, LLC

50 

 

 

 

Golden Pass LNG Terminal LLC

18 

 

Chemical

 

Nederlandse Aardolie Maatschappij B.V.

50 

 

Al-Jubail Petrochemical Company

50 

Qatar Liquefied Gas Company Limited

10 

 

Infineum Holdings B.V.

50 

Qatar Liquefied Gas Company Limited (2)

24 

 

Saudi Yanbu Petrochemical Co.

50 

Ras Laffan Liquefied Natural Gas Company Limited

25 

 

 

 

Ras Laffan Liquefied Natural Gas Company Limited (II)

31 

 

 

 

Ras Laffan Liquefied Natural Gas Company Limited (3)

30 

 

 

 

South Hook LNG Terminal Company Limited

24 

 

 

 

Tengizchevroil, LLP

25 

 

 

 

Terminale GNL Adriatico S.r.l.

71 

 

 

 

71 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

8. Investments, Advances and Long-Term Receivables

 

 

 

 

Dec. 31,

 

Dec. 31,

 

 

 

 

2012 

 

2011 

 

 

 

 

(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

 

437 

 

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.

72 

 


 

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:

 

 

 

 

2012 

 

2011 

 

 

 

(millions of dollars)

 

 

 

 

 

 

Beginning balance

 

10,578 

 

9,614 

 

Accretion expense and other provisions

 

709 

 

581 

 

Reduction due to property sales

 

(176)

 

(854)

 

Payments made

 

(816)

 

(662)

 

Liabilities incurred

 

163 

 

117 

 

Foreign currency translation

 

290 

 

(62)

 

Revisions

 

1,225 

 

1,844 

Ending balance

 

11,973 

 

10,578 

73 

 


 

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:

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Balance beginning at January 1

 

2,881 

 

2,893 

 

2,005 

 

Additions pending the determination of proved reserves

 

868 

 

310 

 

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)

 

40 

 

25 

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:

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Capitalized for a period of one year or less

 

866 

 

310 

 

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

 

401 

 

409 

 

278 

 

Capitalized for a period of greater than ten years

 

236 

 

240 

 

218 

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.

 

 

 

 

 

2012 

 

2011 

 

2010 

Number of projects with first capitalized well drilled in the preceding 12 months

10 

 

 

Number of projects that have exploratory well costs capitalized for a period

 

 

 

 

 

 

of greater than 12 months

 

45 

 

58 

 

59 

 

 

Total

 

55 

 

62 

 

68 

74 

 


 

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

2012 

Drilled

Comment

 

(millions of dollars)

 

  Angola

 

 

 

 

 

   - Perpetua-Zina-Acacia

 

15 

 

2008 - 2009

  Oil field near Pazflor development, awaiting capacity in existing/planned

 

 

 

 

 

  infrastructure.

  Australia

 

 

 

 

 

   - East Pilchard

 

10 

 

2001 

  Gas field near Kipper/Tuna development, awaiting capacity in existing/planned

 

 

 

 

 

  infrastructure.

   - SE Longtom

 

16 

 

2010 

  Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.

  Indonesia

 

 

 

 

 

   - Natuna

 

118 

 

1981 - 1983

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  on contract terms pursuant to executed Heads of Agreement.

  Kazakhstan

 

 

 

 

 

   - Kairan

 

53 

 

2004 - 2007

  Evaluating commercialization and field development alternatives, while continuing

 

 

 

 

 

  discussions with the government regarding the development plan.

  Malaysia

 

 

 

 

 

   - Besar

 

18 

 

1992 - 2010

  Gas field off the east coast of Malaysia; progressing development plan.

   - Bindu

 

 

1995 

  Awaiting capacity in existing/planned infrastructure.

  Nigeria

 

 

 

 

 

   - Bolia

 

15 

 

2002 - 2006

  Evaluating development plan, while continuing discussions with the government

 

 

 

 

 

  regarding regional hub strategy.

   - Bosi

 

79 

 

2002 - 2006

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  regarding development plan.

   - Bosi Central

 

16 

 

2006 

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  regarding development plan.

   - Pegi

 

32 

 

2009 

  Awaiting capacity in existing/planned infrastructure.

   - Usan South Strip

 

16 

 

2011 

  Evaluating development plans to tie into planned infrastructure.

   - Other (5 projects)

 

16 

 

2001 - 2002

  Evaluating and pursuing development of several additional discoveries.

  Norway

 

 

 

 

 

   - Gamma

 

21 

 

2008 - 2009

  Evaluating development plan for tieback to existing production facilities.

   - H-North

 

16 

 

2007 

  Progressing development and commercialization plans.

   - Lavrans

 

24 

 

1995 - 1999

  Development awaiting capacity in existing Kristin production facility; evaluating

 

 

 

 

 

  development concepts for phased ullage scenarios.

   - Other (5 projects)

 

23 

 

2008 - 2010

  Evaluating development plans, including potential for tieback to existing production

 

 

 

 

 

  facilities.

  Papua New Guinea

 

 

 

 

 

   - Juha

 

28 

 

2007 

  Working on development plans to tie into planned LNG facilities.

  United Kingdom

 

 

 

 

 

   - Phyllis

 

 

2004 

  Evaluating development plan for tieback to existing production facilities.

  United States

 

 

 

 

 

   - Tip Top

 

31 

 

2009 

  Evaluating development concept and requisite facility upgrades.

  Total 2012 (28 projects)

 

557 

 

 

 

75 

 


 

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)

 

 

 

 

 

 

 

 

 

 

 

 

2013 

 

 

2,254 

 

 

33 

 

 

 

2014 

 

 

2,041 

 

 

31 

 

 

 

2015 

 

 

1,381 

 

 

26 

 

 

 

2016 

 

 

688 

 

 

 

 

 

2017 

 

 

350 

 

 

 

 

 

2018 and beyond

 

 

1,467 

 

 

14 

 

 

 

     Total

 

 

8,181 

 

 

111 

 

 

 

Net rental cost under both cancelable and noncancelable operating leases incurred during 2012, 2011 and 2010 were as follows:

 

 

 

2012 

 

2011 

 

2010 

 

 

(millions of dollars)

 

 

 

 

 

 

 

Rental cost

 

3,851 

 

4,061 

 

3,762 

Less sublease rental income

 

44 

 

74 

 

90 

Net rental cost

 

3,807 

 

3,987 

 

3,672 

 

12. Earnings Per Share

 

 

 

2012 

 

2011 

 

2010 

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

 

 - 

 

 

12 

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 

76 

 


 

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 

 

496 

 

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.

77 

 


 

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:

 

 

 

 

 

2012 

 

2011 

 

 

 

 

 

 

        (millions of dollars)

 

 

XTO Energy Inc. (1) 

 

 

 

 

 

 

 

6.250% senior note due 2013

 

 - 

 

185 

 

 

 

4.625% senior note due 2013

 

 - 

 

145 

 

 

 

5.750% senior note due 2013

 

 - 

 

346 

 

 

 

4.900% senior note due 2014

 

 254 

 

260 

 

 

 

5.000% senior note due 2015

 

 135 

 

138 

 

 

 

5.300% senior note due 2015

 

 249 

 

255 

 

 

 

5.650% senior note due 2016

 

 217 

 

222 

 

 

 

6.250% senior note due 2017

 

 501 

 

513 

 

 

 

5.500% senior note due 2018

 

 396 

 

402 

 

 

 

6.500% senior note due 2018

 

 495 

 

506 

 

 

 

6.100% senior note due 2036

 

 201 

 

203 

 

 

 

6.750% senior note due 2037

 

 314 

 

317 

 

 

 

6.375% senior note due 2038

 

 240 

 

241 

 

 

 

 

 

 

 

 

 

 

 

Mobil Services (Bahamas) Ltd.

 

 

 

 

 

 

 

Variable note due 2035 (2) 

 

 - 

 

972 

 

 

 

Variable note due 2034 (3) 

 

 311 

 

311 

 

 

 

 

 

 

 

 

 

 

 

Mobil Producing Nigeria Unlimited (4) 

 

 

 

 

 

 

 

Variable notes due 2013-2019

 

 751 

 

543 

 

 

 

 

 

 

 

 

 

 

 

Esso (Thailand) Public Company Ltd. (5) 

 

 

 

 

 

 

 

Variable notes due 2014-2017

 

 414 

 

413 

 

 

 

 

 

 

 

 

 

 

 

Mobil Corporation

 

 

 

 

 

 

 

8.625% debentures due 2021

 

 249 

 

248 

 

 

 

 

 

 

 

 

 

 

 

Industrial revenue bonds due 2014-2051 (6) 

 

 2,690 

 

2,315 

 

 

Other U.S. dollar obligations (7) 

 

 74 

 

496 

 

 

Other foreign currency obligations

 

 6 

 

31 

 

 

Capitalized lease obligations (8) 

 

 431 

 

260 

 

 

 

 

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.

78 

 


 

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.

 

 

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

 

2012 

 

2011 

 

2010 

Grant price (dollars)

 

87.24 

 

79.52 

 

66.07 

 

 

 

 

 

 

 

Value at date of grant:

 

(millions of dollars)

Restricted stock and units settled in stock

 

797 

 

766 

 

672 

Merger-related granted and converted XTO awards

 

 - 

 

 - 

 

250 

Units settled in cash

 

77 

 

72 

 

60 

Total value

 

874 

 

838 

 

982 

 

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.

79 

 


 

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.

 

80 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

16. Litigation and Other Contingencies

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

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 

 

 

53 

 

 

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.

81 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Payments Due by Period

 

 

 

 

2014-

2018 and

 

 

 

2013 

 

2017 

Beyond

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Unconditional purchase obligations (1) 

 

184 

 

624 

 

319 

 

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.

82 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

17. Pension and Other Postretirement Benefits

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

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2012 

 

2011 

 

2012 

 

2011 

 

2012 

 

2011 

 

 

 

(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

 

665 

 

546 

 

648 

 

574 

 

134 

 

121 

 

Interest cost

 

820 

 

792 

 

1,145 

 

1,267 

 

380 

 

393 

 

Actuarial loss/(gain)

 

2,553 

 

1,954 

 

2,335 

 

3,086 

 

1,035 

 

427 

 

Benefits paid (1) (2)

 

(1,294)

 

(1,264)

 

(1,330)

 

(1,470)

 

(476)

 

(473)

 

Foreign exchange rate changes

 

 - 

 

 - 

 

651 

 

(303)

 

13 

 

(11)

 

Japan restructuring and other divestments

 

 - 

 

 - 

 

(3,952)

 

(16)

 

 - 

 

 - 

 

Plan amendments, other

 

 - 

 

 - 

 

105 

 

208 

 

92 

 

92 

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

 

 

 

2012 

 

2011 

 

2012 

 

2011 

 

2012 

 

2011 

 

 

 

(millions of dollars)

Change in plan assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

10,656 

 

10,835 

 

17,117 

 

16,765 

 

538 

 

558 

 

Actual return on plan assets

 

1,457 

 

505 

 

1,541 

 

123 

 

65 

 

 - 

 

Foreign exchange rate changes

 

 - 

 

 - 

 

462 

 

(192)

 

 - 

 

 - 

 

Company contribution

 

1,560 

 

370 

 

1,604 

 

1,623 

 

38 

 

39 

 

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 

 

581 

 

538 

 

(1)   Benefit payments for funded plans.

83 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

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

 

 

 

 

Pension Benefits

 

 

 

U.S.

 

Non-U.S.

 

 

 

2012 

 

2011 

 

2012 

 

2011 

 

 

 

(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

 

 

 

2012 

 

2011 

 

2012 

 

2011 

 

2012 

 

2011 

 

 

 

(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

 

 

 

49 

 

245 

 

 - 

 

 - 

 

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

 

67 

 

74 

 

758 

 

745 

 

85 

 

119 

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.

84 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

Pension Benefits

 

Postretirement

 

 

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

 

 

2012 

 

2011 

 

2010 

 

2012 

 

2011 

 

2010 

 

2012 

 

2011 

 

2010 

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

 

665 

 

546 

 

468 

 

648 

 

574 

 

480 

 

134 

 

121 

 

101 

 

Interest cost

 

820 

 

792 

 

798 

 

1,145 

 

1,267 

 

1,175 

 

380 

 

393 

 

395 

 

Expected return on plan assets

 

(789)

 

(769)

 

(726)

 

(1,109)

 

(1,168)

 

(1,010)

 

(38)

 

(41)

 

(37)

 

Amortization of actuarial loss/(gain)

 

576 

 

485 

 

525 

 

844 

 

647 

 

554 

 

170 

 

162 

 

147 

 

Amortization of prior service cost

 

 

 

 

117 

 

103 

 

84 

 

34 

 

35 

 

52 

 

Net pension enhancement and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    curtailment/settlement cost (1) 

 

333 

 

286 

 

321 

 

1,540 

 

34 

 

 

 - 

 

 - 

 

 - 

Net periodic benefit cost

 

1,612 

 

1,349 

 

1,388 

 

3,185 

 

1,457 

 

1,292 

 

680 

 

670 

 

658 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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 

 

44 

 

1,906 

 

4,133 

 

1,202 

 

1,008 

 

468 

 

251 

 

Amortization of actuarial (loss)/gain

 

(909)

 

(771)

 

(846)

 

(2,384)

 

(681)

 

(563)

 

(170)

 

(162)

 

(147)

 

Prior service cost/(credit)

 

 - 

 

 - 

 

80 

 

71 

 

187 

 

160 

 

 - 

 

 - 

 

26 

 

Amortization of prior service (cost)/credit

 

(7)

 

(9)

 

(2)

 

(117)

 

(103)

 

(84)

 

(34)

 

(35)

 

(52)

 

Foreign exchange rate changes

 

 - 

 

 - 

 

 - 

 

271 

 

(90)

 

96 

 

 3 

 

 - 

 

Total recorded in other comprehensive income

 

969 

 

1,438 

 

(724)

 

(253)

 

3,446 

 

811 

 

807 

 

271 

 

80 

Total recorded in net periodic benefit cost and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    other comprehensive income, before tax

 

2,581 

 

2,787 

 

664 

 

2,932 

 

4,903 

 

2,103 

 

1,487 

 

941 

 

738 

 

Costs for defined contribution plans were $382 million, $378 million and $347 million in 2012, 2011 and 2010, respectively.

85 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

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

 

 

 

 

 

Total Pension and

 

 

 

 

Other Postretirement Benefits

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

(millions of dollars)

(Charge)/credit to other comprehensive income, before tax

 

 

 

 

 

 

 

 

U.S. pension

 

 

(969)

 

(1,438)

 

724 

 

Non-U.S. pension

 

 

253 

 

(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)

 

 

393 

 

1,495 

 

35 

(Charge)/credit to investment in equity companies

 

 

(49)

 

(30)

 

11 

(Charge)/credit to other comprehensive income including noncontrolling

 

 

 

 

 

 

 

interests, after tax

 

 

(1,179)

 

(3,690)

 

(121)

Charge/(credit) to equity of noncontrolling interests

 

 

(124)

 

288 

 

95 

(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.

86 

 


 

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 

 

 

203 

(2)

  

5,308 

(1)

 - 

 

  

5,511 

 

Private equity

 

 - 

 

 - 

 

  

489 

(3)

  

489 

 

 

 - 

 

  

 - 

 

  

448 

(3)

448 

 

Debt securities

 

 

 

 

 

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

  

 

 

 

Corporate

 

 - 

 

3,872 

(4)

 - 

 

  

3,872 

 

 

 - 

 

  

2,005 

(4)

 - 

 

  

2,005 

 

 

Government

 

 - 

 

2,223 

(4)

 - 

 

  

2,223 

 

 

271 

(5)

  

6,643 

(4)

 - 

 

  

6,914 

 

 

Asset-backed

 

 - 

 

10 

(4)

 - 

 

  

10 

 

 

 - 

 

  

95 

(4)

 - 

 

  

95 

 

 

Private mortgages

 

 - 

 

 - 

 

  

 - 

 

  

 - 

 

 

 - 

 

  

 - 

 

  

(6)

 

Real estate funds

 

 - 

 

 - 

 

  

 - 

 

  

 - 

 

 

 - 

 

  

 - 

 

  

293 

(7)

293 

 

Cash

 

 - 

 

198 

(8)

 - 

 

  

198 

 

 

93 

 

  

35 

(9)

 - 

 

  

128 

Total at fair value

 

 - 

 

12,130 

 

 

489 

 

 

12,619 

 

 

567 

 

 

16,757 

 

 

746 

 

 

18,070 

 

Insurance contracts

 

 

 

 

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

  

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

13 

 

 

 

 

  

 

 

  

 

 

  

20 

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.

87 

 


 

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.

 

 - 

 

 

166 

(1)

 - 

 

 

166 

 

 

Non-U.S.

 

 - 

 

 

160 

(1)

 - 

 

  

160 

 

Private equity

 

 - 

 

 

 - 

 

  

(2)

 

Debt securities

 

 

 

 

 

 

  

 

 

  

 

 

 

Corporate

 

 - 

 

 

91 

(3)

 - 

 

  

91 

 

 

Government

 

 - 

 

 

136 

(3)

 - 

 

  

136 

 

 

Asset-backed

 

 - 

 

 

14 

(3)

 - 

 

  

14 

 

Cash

 

 - 

 

 

 

  

 - 

 

  

Total at fair value

 

 - 

 

 

574 

 

 

 

 

581 

 

(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:

 

 

 

2012 

 

 

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

 

458 

 

 

 

393 

 

 

397 

 

 

 

Net realized gains/(losses)

 

 

 

 

 

 - 

 

(14)

 

 

 - 

 

Net unrealized gains/(losses)

 

41 

 

 

 

22 

 

 1 

 

(1)

 

 

 - 

 

Net purchases/(sales)

 

(12)

 

 

 

31 

 

 - 

 

(89)

 

 

 - 

 

Fair value at December 31

 

489 

 

 

 

448 

 

 

293 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

88 

 


 

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 

 

 

194 

(2)

4,835 

(1)

 - 

 

  

5,029 

 

Private equity

 

 - 

 

 - 

 

  

458 

(3)

458 

 

 

 - 

 

  

 - 

 

  

393 

(3)

393 

 

Debt securities

 

 

 

 

 

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

  

 

 

 

Corporate

 

 - 

 

2,728 

(4)

 - 

 

  

2,728 

 

 

(5)

1,857 

(4)

 - 

 

  

1,859 

 

 

Government

 

 - 

 

2,482 

(4)

 - 

 

  

2,482 

 

 

186 

(5)

6,317 

(4)

 - 

 

  

6,503 

 

 

Asset-backed

 

 - 

 

11 

(4)

 - 

 

  

11 

 

 

 - 

 

  

102 

(4)

 - 

 

  

102 

 

 

Private mortgages

 - 

 

 - 

 

  

 - 

 

  

 - 

 

 

 - 

 

  

 - 

 

  

(6)

 

Real estate funds

 

 - 

 

 - 

 

  

 - 

 

  

 - 

 

 

 - 

 

  

 - 

 

  

397 

(7)

397 

 

Cash

 

 - 

 

 71 

(8)

 - 

 

  

71 

 

 

76 

 

  

13 

(9)

 - 

 

  

89 

Total at fair value

 

 - 

 

10,175 

 

 

458 

 

 

10,633 

 

 

458 

 

 

15,713 

 

 

794 

 

 

16,965 

 

Insurance contracts

 

 

 

  

 

 

  

 

 

 

 

 

  

 

 

  

 

 

  

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

23 

 

 

 

 

  

 

 

  

 

 

  

152 

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.

89 

 


 

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.

 

 - 

 

 

166 

(1)

 - 

 

 

166 

 

 

Non-U.S.

 

 - 

 

 

155 

(1)

 - 

 

  

155 

 

Private equity

 

 - 

 

 

 - 

 

  

(2)

 

Debt securities

 

 

 

 

 

 

  

 

 

  

 

 

 

Corporate

 

 - 

 

 

77 

(3)

 - 

 

  

77 

 

 

Government

 

 - 

 

 

120 

(3)

 - 

 

  

120 

 

 

Asset-backed

 

 - 

 

 

12 

(3)

 - 

 

  

12 

 

Cash

 

 - 

 

 

 1 

 

  

 - 

 

  

Total at fair value

 

 - 

 

 

531 

 

 

 

 

538 

 

(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:

 

 

 

2011 

 

 

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

 

408 

 

128 

 

 

315 

 

 

417 

 

 

 

Net realized gains/(losses)

 

 1 

 

 

 

 

 - 

 

 3 

 

 

 - 

 

 - 

Net unrealized gains/(losses)

 

56 

 

 - 

 

 

33 

 

 - 

 

 

 

 

 - 

Net purchases/(sales)

 

(7)

 

(133)

 

 

38 

 

 - 

 

(29)

 

 

 - 

 

(2)

Fair value at December 31

 

458 

 

 - 

 

 

393 

 

 

397 

 

 

 

 - 

90 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

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

 

 

 

Pension Benefits

 

 

U.S.

 

Non-U.S.

 

 

 

2012 

 

2011 

 

 

2012 

 

2011 

 

 

(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 

 

882 

 

 

233 

 

Prior service cost  (2) 

 

 

121 

 

 

21 

 

(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

 

100 

 

1,250 

 

 - 

 

 - 

Benefit payments expected in:

 

 

 

 

 

 

 

 

 

2013 

 

1,643 

 

1,237 

 

453 

 

23 

 

2014 

 

1,611 

 

1,237 

 

469 

 

25 

 

2015 

 

1,597 

 

1,294 

 

482 

 

26 

 

2016 

 

1,558 

 

1,329 

 

494 

 

27 

 

2017 

 

1,510 

 

1,384 

 

506 

 

28 

 

2018 - 2022

 

6,716 

 

7,319 

 

2,633 

 

163 

 

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.

91 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $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 

 

 

 

387 

 

 

183 

 

1,267 

 

 

(492)

 

15,010 

Sales and other operating revenue (1) 

 

11,472 

 

28,854 

 

 

125,088 

 

248,959 

 

 

14,723 

 

24,003 

 

 

24 

 

453,123 

Intersegment revenue

 

8,764 

 

47,507 

 

 

20,963 

 

62,130 

 

 

12,409 

 

9,750 

 

 

258 

 

 - 

Depreciation and depletion expense

 

5,104 

 

7,340 

 

 

594 

 

1,280 

 

 

376 

 

508 

 

 

686 

 

15,888 

Interest revenue

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

117 

 

117 

Interest expense

 

37 

 

13 

 

 

 

36 

 

 

 - 

 

(1)

 

 

239 

 

327 

Income taxes

 

2,025 

 

25,362 

 

 

1,811 

 

1,892 

 

 

755 

 

232 

 

 

(1,032)

 

31,045 

Additions to property, plant and equipment

 

9,697 

 

21,769 

 

 

480 

 

1,153 

 

 

338 

 

659 

 

 

1,083 

 

35,179 

Investments in equity companies

 

4,020 

 

9,147 

 

 

195 

 

2,069 

 

 

233 

 

3,143 

 

 

(277)

 

18,530 

Total assets

 

86,146 

 

140,848 

 

 

18,451 

 

40,956 

 

 

7,238 

 

18,886 

 

 

21,270 

 

333,795 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

 

353 

 

 

198 

 

1,365 

 

 

(447)

 

15,289 

Sales and other operating revenue (1)

 

14,023 

 

32,419 

 

 

120,844 

 

257,779 

 

 

15,466 

 

26,476 

 

 

22 

 

467,029 

Intersegment revenue

 

9,807 

 

49,910 

 

 

18,489 

 

73,549 

 

 

12,226 

 

10,563 

 

 

262 

 

 - 

Depreciation and depletion expense

 

4,879 

 

7,021 

 

 

650 

 

1,560 

 

 

380 

 

458 

 

 

635 

 

15,583 

Interest revenue

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

135 

 

135 

Interest expense

 

30 

 

36 

 

 

10 

 

24 

 

 

 

(1)

 

 

146 

 

247 

Income taxes

 

2,852 

 

25,755 

 

 

1,123 

 

696 

 

 

1,027 

 

465 

 

 

(867)

 

31,051 

Additions to property, plant and equipment

 

10,887 

 

18,934 

 

 

400 

 

1,334 

 

 

241 

 

910 

 

 

932 

 

33,638 

Investments in equity companies

 

2,963 

 

8,439 

 

 

210 

 

1,358 

 

 

253 

 

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 

 

 

770 

 

2,797 

 

 

2,422 

 

2,491 

 

 

(2,117)

 

30,460 

Earnings of equity companies above

 

1,261 

 

8,415 

 

 

23 

 

225 

 

 

171 

 

1,163 

 

 

(581)

 

10,677 

Sales and other operating revenue (1)

 

8,895 

 

26,046 

 

 

93,599 

 

206,042 

 

 

13,402 

 

22,119 

 

 

22 

 

370,125 

Intersegment revenue

 

8,102 

 

39,066 

 

 

13,546 

 

52,697 

 

 

9,694 

 

8,421 

 

 

282 

 

 - 

Depreciation and depletion expense

 

3,506 

 

7,574 

 

 

681 

 

1,565 

 

 

421 

 

432 

 

 

581 

 

14,760 

Interest revenue

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

 - 

 

 - 

 

 

118 

 

118 

Interest expense

 

20 

 

25 

 

 

 

19 

 

 

 

 

 

189 

 

259 

Income taxes

 

2,219 

 

18,627 

 

 

360 

 

560 

 

 

736 

 

347 

 

 

(1,288)

 

21,561 

Additions to property, plant and equipment

 

52,300 

 

16,937 

 

 

888 

 

1,332 

 

 

247 

 

1,733 

 

 

719 

 

74,156 

Investments in equity companies

 

2,636 

 

9,625 

 

 

254 

 

1,240 

 

 

285 

 

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.

92 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Geographic

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue  (1) 

 

2012 

 

2011 

 

2010 

 

 

 

(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

 

2012 

 

2011 

 

2010 

 

 

 

(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 

93 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

19. Income, Sales-Based and Other Taxes

 

 

 

 

 

 

 

 

2012 

 

 

 

 

 

2011 

 

 

 

 

 

2010 

 

 

 

 

 

 

 

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)

 

160 

 

49 

 

(1,191)

 

(1,142)

 

U.S. tax on non-U.S. operations

 

89 

 

 - 

 

89 

 

15 

 

 - 

 

15 

 

46 

 

 - 

 

46 

 

 

 

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

 

602 

 

 - 

 

602 

 

480 

 

 - 

 

480 

 

340 

 

 - 

 

340 

 

 

 

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 

 

776 

 

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

 

154 

 

595 

 

749 

 

181 

 

623 

 

804 

 

201 

 

570 

 

771 

 

 

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:

 

 

 

 

 

2012 

 

2011 

 

2010 

 

 

 

 

(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

 

89 

 

15 

 

46 

State taxes, net of federal tax benefit

 

391 

 

312 

 

221 

Other U.S.

 

(169)

 

50 

 

(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%

94 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

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

 

Tax effects of temporary differences for:

 

2012 

 

2011 

 

 

 

(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

 

2012 

 

2011 

 

 

 

(millions of dollars)

 

 

 

 

 

 

Other current assets

 

(3,540)

 

(4,549)

Other assets, including intangibles, net

 

(3,269)

 

(4,218)

Accounts payable and accrued liabilities

 

263 

 

208 

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.

95 

 


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

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

2012 

 

2011 

 

2010 

 

 

(millions of dollars)

 

 

 

 

 

 

 

Balance at January 1

4,922 

 

4,148 

 

4,725 

 

Additions based on current year's tax positions

1,662 

 

822 

 

830 

 

Additions for prior years' tax positions

2,559 

 

451 

 

620 

 

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)

 

11 

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.

96 

 


 

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

 

 

989 

 

 

 

Total assets

 

 

12,080 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

Current liabilities

 

 

7,398 

 

 

 

 

Long-term debt

 

 

22 

 

 

 

 

Postretirement benefits reserves

 

 

2,066 

 

 

 

 

Other long-term obligations

 

 

826 

 

 

 

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.

  

97 

 


 

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 

 

932 

 

45,897 

 

 

 

 

13,973 

 

7,261 

 

12,201 

 

20,577 

 

15,777 

 

2,207 

 

71,996 

 

Production costs excluding taxes

 

4,044 

 

3,079 

 

2,443 

 

2,395 

 

1,606 

 

488 

 

14,055 

 

Exploration expenses

 

391 

 

292 

 

274 

 

234 

 

513 

 

136 

 

1,840 

 

Depreciation and depletion

 

4,862 

 

848 

 

1,559 

 

2,879 

 

1,785 

 

264 

 

12,197 

 

Taxes other than income

 

1,963 

 

89 

 

513 

 

1,702 

 

2,248 

 

446 

 

6,961 

 

Related income tax

 

1,561 

 

720 

 

5,413 

 

8,091 

 

6,616 

 

281 

 

22,682 

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

1,152 

 

2,233 

 

1,999 

 

5,276 

 

3,009 

 

592 

 

14,261 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,284 

 

 - 

 

6,380 

 

 - 

 

20,017 

 

 - 

 

27,681 

 

 

Transfers

 

1,108 

 

 - 

 

67 

 

 - 

 

5,693 

 

 - 

 

6,868 

 

 

 

 

2,392 

 

 - 

 

6,447 

 

 - 

 

25,710 

 

 - 

 

34,549 

 

Production costs excluding taxes

 

467 

 

 - 

 

369 

 

 - 

 

484 

 

 - 

 

1,320 

 

Exploration expenses

 

 

 - 

 

17 

 

 - 

 

 - 

 

 - 

 

26 

 

Depreciation and depletion

 

176 

 

 - 

 

152 

 

 - 

 

676 

 

 - 

 

1,004 

 

Taxes other than income

 

42 

 

 - 

 

3,569 

 

 - 

 

6,658 

 

 - 

 

10,269 

 

Related income tax

 

 - 

 

 - 

 

 894 

 

 - 

 

8,234 

 

 - 

 

9,128 

 

Results of producing activities for equity companies

 

1,698 

 

 - 

 

1,446 

 

 - 

 

9,658 

 

 - 

 

12,802 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

2,850 

 

2,233 

 

3,445 

 

5,276 

 

12,667 

 

592 

 

27,063 

98 

 


 

  

 

 

 

 

 

 

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 

 

497 

 

14,357 

 

Exploration expenses

 

268 

 

290 

 

599 

 

233 

 

618 

 

73 

 

2,081 

 

Depreciation and depletion

 

4,664 

 

980 

 

1,928 

 

2,159 

 

1,680 

 

236 

 

11,647 

 

Taxes other than income

 

2,157 

 

79 

 

631 

 

2,055 

 

2,164 

 

295 

 

7,381 

 

Related income tax

 

2,445 

 

969 

 

6,842 

 

7,888 

 

6,026 

 

353 

 

24,523 

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

3,128 

 

3,009 

 

3,022 

 

5,268 

 

4,041 

 

820 

 

19,288 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2011 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,356 

 

 - 

 

5,580 

 

 - 

 

18,855 

 

 - 

 

25,791 

 

 

Transfers

 

1,163 

 

 - 

 

103 

 

 - 

 

5,666 

 

 - 

 

6,932 

 

 

 

 

2,519 

 

 - 

 

5,683 

 

 - 

 

24,521 

 

 - 

 

32,723 

 

Production costs excluding taxes

 

482 

 

 - 

 

315 

 

 - 

 

378 

 

 - 

 

1,175 

 

Exploration expenses

 

10 

 

 - 

 

13 

 

 - 

 

 

 - 

 

23 

 

Depreciation and depletion

 

151 

 

 - 

 

160 

 

 - 

 

576 

 

 - 

 

887 

 

Taxes other than income

 

36 

 

 - 

 

2,995 

 

 - 

 

6,173 

 

 - 

 

9,204 

 

Related income tax

 

 - 

 

 - 

 

847 

 

 - 

 

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 

 

820 

 

31,839 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

5,334 

 

1,218 

 

6,055 

 

4,227 

 

4,578 

 

696 

 

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 

 

462 

 

12,108 

 

Exploration expenses

 

283 

 

464 

 

394 

 

587 

 

360 

 

56 

 

2,144 

 

Depreciation and depletion

 

3,350 

 

1,015 

 

2,531 

 

2,580 

 

1,141 

 

219 

 

10,836 

 

Taxes other than income

 

1,188 

 

86 

 

482 

 

1,742 

 

1,298 

 

204 

 

5,000 

 

Related income tax

 

2,093 

 

715 

 

4,728 

 

6,068 

 

3,852 

 

262 

 

17,718 

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

2,696 

 

2,158 

 

2,323 

 

4,330 

 

2,650 

 

616 

 

14,773 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2010 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,012 

 

 - 

 

5,050 

 

 - 

 

12,682 

 

 

18,744 

 

 

Transfers

 

867 

 

 - 

 

68 

 

 - 

 

3,817 

 

 

4,752 

 

 

 

 

1,879 

 

 - 

 

5,118 

 

 - 

 

16,499 

 

 

23,496 

 

Production costs excluding taxes

 

481 

 

 - 

 

294 

 

 - 

 

320 

 

 

1,095 

 

Exploration expenses

 

 

 - 

 

19 

 

 - 

 

 2 

 

 - 

 

25 

 

Depreciation and depletion

 

157 

 

 - 

 

188 

 

 - 

 

455 

 

 

800 

 

Taxes other than income

 

32 

 

 - 

 

2,515 

 

 - 

 

3,844 

 

 

6,391 

 

Related income tax

 

 - 

 

 - 

 

 815 

 

 - 

 

 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 

 

616 

 

23,848 

99 

 


 

  

 

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 

 

198 

 

874 

 

1,610 

 

971 

 

19,645 

 

 

- Unproved

 

25,769 

 

1,456 

 

89 

 

430 

 

710 

 

162 

 

28,616 

 

 

Total property costs

 

 

37,850 

 

5,367 

 

287 

 

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

 

76 

 

 - 

 

 

 - 

 

 - 

 

 - 

 

81 

 

 

- Unproved

 

39 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

39 

 

 

Total property costs

 

 

115 

 

 - 

 

 

 - 

 

 - 

 

 - 

 

120 

 

Producing assets

 

 

4,216 

 

 - 

 

5,736 

 

 - 

 

8,169 

 

 - 

 

18,121 

 

Incomplete construction

 

 

304 

 

 - 

 

118 

 

 - 

 

822 

 

 - 

 

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 

 

96 

 

919 

 

1,567 

 

954 

 

18,342 

 

 

- Unproved

 

25,398 

 

1,402 

 

67 

 

430 

 

755 

 

128 

 

28,180 

 

 

Total property costs

 

 

36,367 

 

5,239 

 

163 

 

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 

 

964 

 

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

 

76 

 

 - 

 

 

 - 

 

 - 

 

 - 

 

80 

 

 

- Unproved

 

25 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

25 

 

 

Total property costs

 

 

101 

 

 - 

 

 

 - 

 

 - 

 

 - 

 

105 

 

Producing assets

 

 

3,510 

 

 - 

 

5,383 

 

 - 

 

8,155 

 

 - 

 

17,048 

 

Incomplete construction

 

 

183 

 

 - 

 

212 

 

 - 

 

548 

 

 - 

 

943 

 

 

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 

100 

 


 

  

 

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

 

192 

 

 2 

 

 95 

 

 - 

 

43 

 

 - 

 

332 

 

 

 

- Unproved

 

1,717 

 

74 

 

 24 

 

 15 

 

 

 31 

 

1,861 

 

 

Exploration costs

 

 

601 

 

405 

 

454 

 

520 

 

554 

 

248 

 

2,782 

 

 

Development costs

 

 

7,172 

 

7,601 

 

2,637 

 

3,081 

 

3,347 

 

2,333 

 

26,171 

 

 

Total costs incurred for consolidated subsidiaries

 

9,682 

 

8,082 

 

3,210 

 

3,616 

 

3,944 

 

2,612 

 

31,146 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

 

 

- Unproved

 

14 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

14 

 

 

Exploration costs

 

 

45 

 

 - 

 

34 

 

 - 

 

 - 

 

 - 

 

79 

 

 

Development costs

 

 

504 

 

 - 

 

156 

 

 - 

 

651 

 

 - 

 

1,311 

 

 

Total costs incurred for equity companies

 

563 

 

 - 

 

190 

 

 - 

 

651 

 

 - 

 

1,404 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

259 

 

 - 

 

 

 

96 

 

 - 

 

355 

 

 

 

- Unproved

 

2,685 

 

178 

 

 

 - 

 

 546 

 

 - 

 

3,409 

 

 

Exploration costs

 

 

465 

 

372 

 

640 

 

303 

 

518 

 

154 

 

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

 

23 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

23 

 

 

Exploration costs

 

 

19 

 

 - 

 

32 

 

 - 

 

 

 - 

 

51 

 

 

Development costs

 

 

339 

 

 - 

 

164 

 

 - 

 

649 

 

 - 

 

1,152 

 

 

Total costs incurred for equity companies

 

381 

 

 - 

 

196 

 

 - 

 

649 

 

 - 

 

1,226 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

21,633 

 

 - 

 

 41 

 

 

 115 

 

 

21,792 

 

 

 

- Unproved

 

23,509 

 

136 

 

23 

 

 

 

 - 

 

23,668 

 

 

Exploration costs

 

 

690 

 

527 

 

550 

 

453 

 

545 

 

228 

 

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

 

 1 

 

 - 

 

 - 

 

 - 

 

 - 

 

 - 

 

 1 

 

 

Exploration costs

 

 

 

 - 

 

56 

 

 - 

 

 2 

 

 - 

 

62 

 

 

Development costs

 

 

323 

 

 - 

 

225 

 

 - 

 

303 

 

 

851 

 

 

Total costs incurred for equity companies

 

328 

 

 - 

 

281 

 

 - 

 

305 

 

 

914 

101 

 


 

  

 

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.

102 

 


 

  

 

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 

172 

487 

1,907 

1,999 

288 

6,469 

 

2,055 

 

 

691 

 

9,215 

 

Revisions

57 

10 

53 

89 

49 

265 

 

89 

 

 

14 

 

368 

 

Improved recovery

 - 

 - 

 - 

 - 

 

 - 

 

 

 - 

 

 

Purchases

374 

 - 

 - 

 - 

 - 

378 

 

 - 

 

 

 - 

 

378 

 

Sales

(19)

 - 

 - 

(2)

 - 

 - 

(21)

 

 - 

 

 

 - 

 

(21)

 

Extensions/discoveries

43 

11 

34 

90 

 - 

182 

 

 - 

 

 

 - 

 

182 

 

Production

(123)

(30)

(121)

(229)

(119)

(21)

(643)

 

(42)

 

  

(24)

 

(709)

December 31, 2010

1,952 

163 

423 

1,799 

2,023 

275 

6,635 

 

2,102 

 

 

681 

 

9,418 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2010

356 

 - 

30 

 - 

2,050 

 - 

2,436 

 

 - 

 

 

 - 

 

2,436 

 

Revisions

17 

 - 

 - 

(30)

 - 

(10)

 

 - 

 

 

 - 

 

(10)

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

 - 

 

 - 

 

Purchases

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

 - 

 

 - 

 

Sales

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

 - 

 

 - 

 

Extensions/discoveries

 - 

 - 

 - 

 - 

 

 - 

 

 

 - 

 

 

Production

(25)

 - 

(2)

 - 

(147)

 - 

(174)

 

 - 

 

 

 - 

 

(174)

December 31, 2010

351 

 - 

31 

 - 

1,873 

 - 

2,255 

 

 - 

 

 

 - 

 

2,255 

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

2,303 

163 

454 

1,799 

3,896 

275 

8,890 

 

2,102 

 

 

681 

 

11,673 

103 

 


 

  

 

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 

138 

350 

1,589 

1,839 

178 

5,773 

 

862 

 

2,102 

 

 

681 

 

9,418 

 

Revisions

29 

10 

68 

52 

(55)

109 

 

106 

 

53 

 

  

(4)

 

264 

 

Improved recovery

 

 

 

 

 

 

Purchases

 

14 

 

 

 

 

16 

 

Sales

(3)

(11)

(24)

(38)

 

(14)

 

 

 

 

(52)

 

Extensions/discoveries

55 

57 

116 

 

18 

 

995 

 

 

 

1,129 

 

Production

(102)

(19)

(80)

(179)

(120)

(13)

(513)

 

(81)

 

(44)

 

 

(24)

 

(662)

December 31, 2011

1,660 

118 

317 

1,463 

1,721 

170 

5,449 

 

905 

 

3,106 

 

 

653 

 

10,113 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2011

350 

31 

1,394 

1,775 

 

480 

 

 

 

 

2,255 

 

Revisions

24 

(21)

 

 

 

 

 

 

Improved recovery

 

 

 

 

 

 

Purchases

 

 

 

 

 

 

Sales

(2)

(2)

 

 

 

 

 

(2)

 

Extensions/discoveries

12 

12 

 

25 

 

 

 

 

37 

 

Production

(24)

(2)

(130)

(156)

 

(25)

 

 

 

 

(181)

December 31, 2011

348 

29 

1,255 

1,632 

 

483 

 

 

 

 

2,115 

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2011

2,008 

118 

346 

1,463 

2,976 

170 

7,081 

 

1,388 

 

3,106 

 

 

653 

 

12,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2012

1,660 

118 

317 

1,463 

1,721 

170 

5,449 

 

905 

 

3,106 

 

 

653 

 

10,113 

 

Revisions

25 

33 

14 

20 

(10)

87 

 

 

265 

 

  

(29)

 

326 

 

Improved recovery

 

 

 

 

 

 

Purchases

163 

20 

183 

 

36 

 

 

 

 

219 

 

Sales

(15)

(1)

(8)

(58)

(82)

 

(4)

 

 

 

 

(86)

 

Extensions/discoveries

166 

138 

41 

362 

 

164 

 

234 

 

 

 

760 

 

Production

(100)

(18)

(62)

(173)

(117)

(12)

(482)

 

(73)

 

(45)

 

 

(25)

 

(625)

December 31, 2012

1,905 

270 

289 

1,293 

1,604 

163 

5,524 

 

1,031 

 

3,560 

 

 

599 

 

10,714 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2012

348 

29 

1,255 

1,632 

 

483 

 

 

 

 

2,115 

 

Revisions

(2)

131 

130 

 

15 

 

 

 

 

145 

 

Improved recovery

16 

16 

 

 

 

 

 

16 

 

Purchases

 

 

 

 

 

 

Sales

 

 

 

 

 

 

Extensions/discoveries

 

 

 

 

 

 

Production

(22)

(2)

(126)

(150)

 

(24)

 

 

 

 

(174)

December 31, 2012

340 

28 

1,260 

1,628 

 

474 

 

 

 

 

2,102 

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2012

2,245 

270 

317 

1,293 

2,864 

163 

7,152 

 

1,505 

 

3,560 

 

 

599 

 

12,816 

 

(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.

104 

 


 

  

 

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, 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,478 

133 

 

361 

1,055 

1,306 

139 

4,472 

 

519 

 

681 

 

5,672 

 

 

Equity companies

271 

 - 

 

21 

 - 

1,623 

 - 

1,915 

 

 - 

 

 - 

 

1,915 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

474 

30 

 

62 

744 

717 

136 

2,163 

 

1,583 

 

 - 

 

3,746 

 

 

Equity companies

80 

 - 

 

10 

 - 

250 

 - 

340 

 

 - 

 

 - 

 

340 

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

2,303 

163 

 

454 

1,799 

3,896 

275 

8,890 

 

2,102 

 

681 

 

11,673 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,452 

109 

 

302 

1,050 

1,160 

126 

4,199 

 

519 

 

653 

 

5,371 

 

 

Equity companies

270 

 - 

 

28 

 - 

1,457 

 - 

1,755 

 

 - 

 

 - 

 

1,755 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

567 

26 

 

74 

625 

727 

136 

2,155 

 

2,587 

 

 - 

 

4,742 

 

 

Equity companies

83 

 - 

 

 - 

276 

 - 

360 

 

 - 

 

 - 

 

360 

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

2,372 

135 

 

405 

1,675 

3,620 

262 

8,469 

  

3,106 

 

653 

 

12,228 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 1,489 

 124 

 

 268 

 1,004 

 1,080 

 116 

 4,081 

 

 543 

 

 599 

 

 5,223 

 

 

Equity companies

 264 

 - 

 

 28 

 - 

 1,423 

 - 

 1,715 

 

 - 

 

 - 

 

 1,715 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 921 

 163 

 

 77 

 497 

 682 

 134 

 2,474 

 

 3,017 

 

 - 

 

 5,491 

 

 

Equity companies

 84 

 - 

 

 - 

 - 

 303 

 - 

 387 

 

 - 

 

 - 

 

 387 

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 2,758 

 287 

 

 373 

 1,501 

 3,488 

 250 

 8,657 

(4)

 3,560 

 

 599 

 

 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.

105 

 


 

  

 

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 

920 

8,303 

7,440 

34,442 

 

14,955 

 

 

Revisions

832 

123 

(26)

(333)

42 

644 

 

475 

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 5 

 

 

Purchases

12,774 

 - 

15 

 - 

 - 

 - 

12,789 

 

2,510 

 

 

Sales

(104)

(2)

 - 

 - 

 - 

 - 

(106)

 

(38)

 

 

Extensions/discoveries

1,861 

49 

25 

25 

1,964 

 

509 

 

 

Production

(1,057)

(234)

(719)

(43)

(735)

(132)

(2,920)

 

(1,196)

 

December 31, 2010

25,994 

1,258 

4,042 

908 

7,260 

7,351 

46,813 

 

17,220 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2010

114 

 - 

11,450 

 - 

22,001 

 - 

33,565 

 

8,030 

 

 

Revisions

 - 

(4)

 - 

231 

 - 

235 

 

30 

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Purchases

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Sales

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Extensions/discoveries

 - 

 - 

24 

 - 

 - 

 - 

24 

 

 

 

Production

(5)

 - 

(724)

 - 

(1,093)

 - 

(1,822)

 

(478)

 

December 31, 2010

117 

 - 

10,746 

 - 

21,139 

 - 

32,002 

 

7,589 

 

Total proved reserves at December 31, 2010

26,111 

1,258 

14,788 

908 

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 

908 

7,260 

7,351 

46,813 

 

17,220 

 

 

Revisions

(236)

55 

310 

113 

(231)

28 

39 

 

271 

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Purchases

303 

 - 

 - 

 - 

 - 

 - 

303 

 

67 

 

 

Sales

(32)

(347)

(140)

 - 

 - 

 - 

(519)

 

(138)

 

 

Extensions/discoveries

1,779 

42 

29 

 - 

192 

 - 

2,042 

 

1,469 

 

 

Production

(1,554)

(173)

(655)

(39)

(750)

(132)

(3,303)

 

(1,213)

 

December 31, 2011

26,254 

835 

3,586 

982 

6,471 

7,247 

45,375 

 

17,676 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2011

117 

 - 

10,746 

 - 

21,139 

 - 

32,002 

 

7,589 

 

 

Revisions

 - 

53 

 - 

(29)

 - 

25 

 

10 

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Purchases

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Sales

(1)

 - 

(3)

 - 

 - 

 - 

(4)

 

(3)

 

 

Extensions/discoveries

 - 

 - 

13 

 - 

627 

 - 

640 

 

144 

 

 

Production

(5)

 - 

(640)

 - 

(1,171)

 - 

(1,816)

 

(484)

 

December 31, 2011

112 

 - 

10,169 

 - 

20,566 

 - 

30,847 

 

7,256 

 

Total proved reserves at December 31, 2011

26,366 

835 

13,755 

982 

27,037 

7,247 

76,222 

 

24,932 

 

 

(See footnotes on next page)

106 

 


 

  

 

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2012

26,254 

835 

3,586 

982 

6,471 

7,247 

45,375 

 

17,676 

 

 

Revisions

(2,888)

168 

168 

 2 

(106)

465 

(2,191)

 

(39)

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 

 

Purchases

 503 

 - 

 6 

 - 

 - 

 - 

 509 

 

304 

 

 

Sales

(181)

(20)

(140)

(12)

 - 

 - 

(353)

 

(145)

 

 

Extensions/discoveries

 4,045 

 95 

 184 

 - 

 59 

 - 

 4,383 

 

1,490 

 

 

Production

(1,518)

(153)

(555)

(43)

(579)

(144)

(2,992)

 

(1,124)

 

December 31, 2012

 26,215 

 925 

 3,249 

 929 

 5,845 

 7,568 

 44,731 

 

 18,169 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2012

112 

 - 

10,169 

 - 

20,566 

 - 

30,847 

 

7,256 

 

 

Revisions

49 

 - 

17 

 - 

252 

 - 

318 

 

198 

 

 

Improved recovery

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 16 

 

 

Purchases

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Sales

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Extensions/discoveries

 - 

 - 

 - 

 - 

 - 

 - 

 - 

 

 - 

 

 

Production

(6)

 - 

(651)

 - 

(1,148)

 - 

(1,805)

 

(475)

 

December 31, 2012

 155 

 - 

 9,535 

 - 

 19,670 

 - 

 29,360 

 

 6,995 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2012

 26,370 

 925 

 12,784 

 929 

 25,515 

 7,568 

 74,091 

 

 25,164 

 

 

(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.

107 

 


 

  

 

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

 

 

 

 

 

equivalent barrels)

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

15,344 

1,077 

3,516 

711 

6,593 

1,174 

28,415 

 

10,408 

 

 

 

Equity companies

97 

 - 

8,167 

 - 

 20,494 

 - 

 28,758 

 

 6,708 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2010

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

10,650 

181 

526 

197 

667 

6,177 

18,398 

 

6,812 

 

 

 

Equity companies

20 

 - 

2,579 

 - 

 645 

 - 

 3,244 

 

 881 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2010

26,111 

1,258 

14,788 

908 

28,399 

7,351 

78,815 

 

24,809 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

15,450 

658 

3,041 

853 

5,762 

1,070 

26,834 

 

9,843 

 

 

 

Equity companies

83 

 - 

7,588 

 - 

19,305 

 - 

26,976 

 

6,251 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

10,804 

177 

545 

129 

709 

6,177 

18,541 

 

7,833 

 

 

 

Equity companies

29 

 - 

2,581 

 - 

1,261 

 - 

3,871 

 

1,005 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2011

26,366 

835 

13,755 

982 

27,037 

7,247 

76,222 

 

24,932 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 14,471 

 670 

 2,526 

 814 

 5,150 

 1,012 

 24,643 

 

 9,330 

 

 

 

Equity companies

 126 

 - 

 7,057 

 - 

 18,431 

 - 

 25,614 

 

 5,984 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

 11,744 

 255 

 723 

 115 

 695 

 6,556 

 20,088 

 

 8,839 

 

 

 

Equity companies

 29 

 - 

 2,478 

 - 

 1,239 

 - 

 3,746 

 

 1,011 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2012

 26,370 

 925 

 12,784 

 929 

 25,515 

 7,568 

 74,091 

 

 25,164 

 

 

(See footnotes on previous page)

108 

 


 

  

 

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.

109 

 


 

  

 

 

 

 

 

 

 

 

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.

110 

 


 

  

 

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

 

Consolidated and Equity Interests

 

 

 

 

2010 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

210 

 

 

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 

 

 

843 

 

 

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

 

 

 

 

2011 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

309 

 

 

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 

 

111 

 


 

  

 

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

 

Consolidated and Equity Interests (continued)

 

 

 

 

2012 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2011

 

152,244 

 

 

86,560 

 

 

238,804 

 

 

 

 

 

 

 

 

 

 

 

 

 

Value of reserves added during the year due to extensions, discoveries,

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

7,952 

 

 

531 

 

 

8,483 

 

Changes in value of previous-year reserves due to:

 

 

 

 

 

 

 

 

 

 

Sales and transfers of oil and gas produced during the year, net of

 

 

 

 

 

 

 

 

 

 

 

production (lifting) costs

 

(51,752)

 

 

(23,022)

 

 

(74,774)

 

 

Development costs incurred during the year

 

24,596 

 

 

1,186 

 

 

25,782 

 

 

Net change in prices, lifting and development costs

 

(31,382)

 

 

5,656 

 

 

(25,726)

 

 

Revisions of previous reserves estimates

 

3,876 

 

 

7,018 

 

 

10,894 

 

 

Accretion of discount

 

19,676 

 

 

8,846 

 

 

28,522 

 

Net change in income taxes

 

12,339 

 

 

463 

 

 

12,802 

 

 

 

Total change in the standardized measure during the year

 

(14,695)

 

 

678 

 

 

(14,017)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2012

 

137,549 

 

 

87,238 

 

 

224,787 

 

112 

 


 

OPERATING SUMMARY (unaudited)

 

 

 

2012 

 

2011 

 

2010 

 

2009 

 

2008 

Production of crude oil, natural gas liquids, synthetic oil and bitumen

 

 

 

 

 

 

 

 

 

 

Net production

(thousands of barrels daily)

 

 

United States

 418 

 

423 

 

408 

 

384 

 

367 

 

 

Canada/South America

 251 

 

252 

 

263 

 

267 

 

292 

 

 

Europe

 207 

 

270 

 

335 

 

379 

 

428 

 

 

Africa

 487 

 

508 

 

628 

 

685 

 

652 

 

 

Asia

 772 

 

808 

 

730 

 

607 

 

599 

 

 

Australia/Oceania

 50 

 

51 

 

58 

 

65 

 

67 

 

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

 362 

 

412 

 

569 

 

643 

 

640 

 

 

Europe

 3,220 

 

3,448 

 

3,836 

 

3,689 

 

3,949 

 

 

Africa

 17 

 

 

14 

 

19 

 

32 

 

 

Asia

 4,538 

 

5,047 

 

4,801 

 

3,332 

 

2,870 

 

 

Australia/Oceania

 363 

 

331 

 

332 

 

315 

 

358 

 

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

 435 

 

430 

 

444 

 

413 

 

446 

 

 

Europe

 1,504 

 

1,528 

 

1,538 

 

1,548 

 

1,601 

 

 

Asia Pacific

 998 

 

1,180 

 

1,249 

 

1,328 

 

1,352 

 

 

Other Non-U.S.

 261 

 

292 

 

269 

 

294 

 

315 

 

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

 453 

 

455 

 

450 

 

413 

 

444 

 

 

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

 200 

 

276 

 

280 

 

279 

 

419 

 

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

 473 

 

492 

 

476 

 

536 

 

607 

 

 

Heavy fuels

 515 

 

588 

 

603 

 

598 

 

636 

 

 

Specialty petroleum products

 750 

 

773 

 

773 

 

708 

 

768 

 

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.

113 

 


 

 

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

 

114 

 


 

 

 

 

 

 

/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)

 

115 

 


 

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).*

 

 

12

Computation of ratio of earnings to fixed charges.

 

 

14

Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2008).

 

 

21

Subsidiaries of the registrant.

 

 

23

Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

 

 

31.1

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.

 

 

31.2

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.

 

 

31.3

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.

 

116 

 


 

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.

 

 

101

Interactive data files.

 

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

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

 

117