10-K 1 xom10k2012.htm FORM 10-K  

 

 

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.

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

The Corporation’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