10-K 1 xom10k2014.htm FORM 10-K  

 

 

2014

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

or

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

NEW JERSEY

13-5409005

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)

 

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

 

 

 

Title of Each Class

Name of Each Exchange

on Which Registered

Common Stock, without par value (4,194,690,266 shares outstanding at January 31, 2015)

New York Stock  Exchange

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

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

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

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

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

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

 

Large accelerated filer               Accelerated filer    

Non-accelerated filer             Smaller reporting company    

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $100.68 on the New York Stock Exchange composite tape, was in excess of $429 billion.

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

 

 

 

 


 

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014

TABLE OF CONTENTS

 

 

 

PART I

 

 

 

Item 1.

Business

           1 

 

 

 

Item 1A.

Risk Factors

           2 

 

 

 

Item 1B.

Unresolved Staff Comments

           4 

 

 

 

Item 2.

Properties

           5 

 

 

 

Item 3.

Legal Proceedings

         26 

 

 

 

Item 4.

Mine Safety Disclosures

         26 

 

 

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

         27 

 

PART II

 

 

 

Item 5.

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

         30 

 

 

 

Item 6.

Selected Financial Data

         30 

 

 

 

Item 7.

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

         30 

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

         30 

 

 

 

Item 8.

Financial Statements and Supplementary Data

         31 

 

 

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

         31 

 

 

 

Item 9A.

Controls and Procedures

         31 

 

 

 

Item 9B.

Other Information

         31 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

         32  

 

 

 

Item 11.

Executive Compensation

         32  

 

 

 

Item 12.

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

         32  

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

         33  

 

 

 

Item 14.

Principal Accounting Fees and Services

         33  

 

PART IV

 

 

 

Item 15.

Exhibits, Financial Statement Schedules

         33  

 

 

Financial Section

         34  

 

 

Signatures

      113  

 

 

Index to Exhibits

      115  

 

 

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

 

 

 

Exhibits 31 and 32 — Certifications

 

  

 


 

PART I

ITEM 1.       BUSINESS

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso, Mobil or XTO. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms like Corporation, Company, our, we  and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2014 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $6.2 billion, of which $3.5 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to remain in this range in 2015 and 2016 (with capital expenditures approximately 40 percent of the total).

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

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Quarterly Information”, “Note 18: Disclosures about Segments and Related Information” and “Operating Summary”. Information on oil and gas reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report.

ExxonMobil has a long‑standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business segments. Information on Company-sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2014. For technology licensed to third parties, revenues totaled approximately $148 million in 2014. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

The number of regular employees was 75.3 thousand, 75.0 thousand, and 76.9 thousand at years ended 2014, 2013 and 2012, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 8.4 thousand, 9.8 thousand, and 11.1 thousand at years ended 2014, 2013 and 2012, respectively.

Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be found in “Item 1A–Risk Factors” and “Item 2–Properties” in this report.

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

1 


 

ITEM 1A.       RISK FACTORS

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

Supply and Demand

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

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

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

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

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

Government and Political Factors

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

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

Restrictions on doing business. ExxonMobil is subject to laws and sanctions imposed by the U.S. or by other jurisdictions where we do business that may prohibit ExxonMobil or certain of its affiliates from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to competitors who may not be subject to comparable restrictions.

Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.

2 


 

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

  

·           

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

·           

price controls;

·           

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

·           

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

·           

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

·           

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

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

We also may be adversely affected by the outcome of litigation, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur, or by government enforcement proceedings alleging non-compliance with applicable laws or regulations.

Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.

Climate change and greenhouse gas restrictions. Due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

Government sponsorship of alternative energy. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the Global Climate and Energy Project at Stanford University and research into liquid products from algae and biomass that can be further converted to transportation fuels. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing the energy products of the future in a cost-competitive manner. See “Management Effectiveness” below.

Management Effectiveness

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.

Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources on line on schedule and within budget.

Project management. The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role.

3 


 

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements, regular reappraisal of our asset portfolio, and the recruitment, development and retention of high caliber employees.

Research and development. To maintain our competitive position, especially in light of the technological nature of our businesses and the need for continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful and able to adapt to a changing market and policy environment.

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

Business risks also include the risk of cybersecurity breaches. If our systems for protecting against cybersecurity risks prove not to be sufficient, ExxonMobil could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, or its business operations disrupted.

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our rigorous disaster preparedness and response planning, as well as business continuity planning.

Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

4 


 

Item 2.       Properties

Information with regard to oil and gas producing activities follows:

 

1. Disclosure of Reserves

A. Summary of Oil and Gas Reserves at Year-End 2014

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2014, that would cause a significant change in the estimated proved reserves as of that date.

 

 

 

 

 

 

Crude

Natural Gas

 

Synthetic

Natural

Oil-Equivalent

 

 

 

 

 

Oil

Liquids

Bitumen

Oil

Gas

Basis

 

 

 

 

 

(million bbls)

(million bbls)

(million bbls)

(million bbls)

(billion cubic ft)

(million bbls)

Proved Reserves

 

 

 

 

 

 

 

Developed

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,215

287

-

-

14,169

3,864

 

 

 

Canada/South America (1) 

98

13

2,122

534

615

2,869

 

 

 

Europe

170

35

-

-

1,870

517

 

 

 

Africa

722

172

-

-

764

1,021

 

 

 

Asia

1,481

134

-

-

5,031

2,453

 

 

 

Australia/Oceania

74

38

-

-

2,179

475

 

 

 

 

Total Consolidated

3,760

679

2,122

534

24,628

11,199

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

259

10

-

-

194

301

 

 

 

Europe

26

-

-

-

6,484

1,107

 

 

 

Asia

822

366

-

-

16,305

3,906

 

 

 

 

Total Equity Company

1,107

376

-

-

22,983

5,314

 

 

 

 

Total Developed

4,867

1,055

2,122

534

47,611

16,513

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

893

341

-

-

11,818

3,203

 

 

 

Canada/South America (1) 

184

6

2,111

-

611

2,403

 

 

 

Europe

29

13

-

-

513

127

 

 

 

Africa

380

21

-

-

47

409

 

 

 

Asia

651

-

-

-

429

723

 

 

 

Australia/Oceania

67

32

-

-

5,097

949

 

 

 

 

Total Consolidated

2,204

413

2,111

-

18,515

7,814

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

69

6

-

-

78

88

 

 

 

Europe

1

-

-

-

1,934

323

 

 

 

Asia

278

53

-

-

1,200

531

 

 

 

 

Total Equity Company

348

59

-

-

3,212

942

 

 

 

 

Total Undeveloped

2,552

472

2,111

-

21,727

8,756

Total Proved Reserves

7,419

1,527

4,233

534

69,338

25,269

 

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

5 


 

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

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

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well and reservoir information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and gas price levels.

B. Technologies Used in Establishing Proved Reserves Additions in 2014

Additions to ExxonMobil’s proved reserves in 2014 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 3-D and 4-D seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves

ExxonMobil has a dedicated Global Reserves group that provides technical oversight and is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude and natural gas liquids, bitumen, synthetic oil and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The Manager of the Global Reserves group has more than 30 years of experience in reservoir engineering and reserves assessment and has a degree in Engineering. He is an active member of the Society of Petroleum Engineers (SPE) and previously served on the SPE Oil and Gas Reserves Committee. The group is managed by and staffed with individuals that have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes individuals who hold advanced degrees in either Engineering or Geology. Several members of the group hold professional registrations in their field of expertise, and members have served on the SPE Oil and Gas Reserves Committee.

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

 

6 


 

 2. Proved Undeveloped Reserves

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

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Development projects typically take two to four years from the time of recording  proved undeveloped reserves to the start of production. However, the development time for large and complex projects can exceed five years. During 2014, discoveries and extensions related to new projects added approximately 0.6 GOEB of proved undeveloped reserves. The largest of these additions were related to planned drilling in the United States and project funding in Angola, Russia and Kazakhstan. Overall, investments of $24.2 billion were made by the Corporation during 2014 to progress the development of reported proved undeveloped reserves, including $22.4 billion for oil and gas producing activities and an additional $1.8 billion for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 74 percent of the $32.7 billion in total reported Upstream capital and exploration expenditures.

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

7 


 

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

A. Oil and Gas Production

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

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

 

(thousands of barrels daily)

Crude oil and natural gas liquids production

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

304

85

 

283

85

 

274

81

 

 

Canada/South America (1) 

 

52

9

 

57

10

 

49

10

 

 

Europe

 

151

28

 

157

27

 

170

33

 

 

Africa

 

469

20

 

451

18

 

472

15

 

 

Asia

 

293

26

 

313

30

 

319

43

 

 

Australia/Oceania

 

39

20

 

29

19

 

32

18

 

 

 

Total Consolidated Subsidiaries

 

1,308

188

 

1,290

189

 

1,316

200

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

63

2

 

61

2

 

61

2

 

 

Europe

 

5

-

 

6

-

 

4

-

 

 

Asia

 

236

69

 

373

68

 

345

65

 

 

 

Total Equity Companies

 

304

71

 

440

70

 

410

67

 

 

 

 

 

 

 

 

 

 

 

 

 

Total crude oil and natural gas liquids production

 

1,612

259

 

1,730

259

 

1,726

267

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/South America

 

180

 

 

148

 

 

123

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Synthetic oil production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/South America

 

60

 

 

65

 

 

69

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liquids production

 

2,111

 

 

2,202

 

 

2,185

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

3,374

 

 

3,530

 

 

3,819

 

 

 

Canada/South America (1) 

 

310

 

 

354

 

 

362

 

 

 

Europe

 

1,226

 

 

1,294

 

 

1,446

 

 

 

Africa

 

4

 

 

6

 

 

17

 

 

 

Asia

 

1,067

 

 

1,180

 

 

1,445

 

 

 

Australia/Oceania

 

512

 

 

351

 

 

363

 

 

 

 

Total Consolidated Subsidiaries

 

6,493

 

 

6,715

 

 

7,452

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

30

 

 

15

 

 

3

 

 

 

Europe

 

1,590

 

 

1,957

 

 

1,774

 

 

 

Asia

 

3,032

 

 

3,149

 

 

3,093

 

 

 

 

Total Equity Companies

 

4,652

 

 

5,121

 

 

4,870

 

Total natural gas production available for sale

 

11,145

 

 

11,836

 

 

12,322

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production

 

3,969

 

 

4,175

 

 

4,239

 

(1)   South America includes liquids production for 2012 of one thousand barrels daily and natural gas production available for sale for 2014, 2013 and 2012 of 21 million, 28 million, and 38 million cubic feet daily, respectively.

8 


 

B. Production Prices and Production Costs

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

 

 

 

 

 

 

United

Canada/

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

S. America

Europe

 

Africa

 

Asia

Oceania

Total

During 2014

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

84.00

 

86.46

 

96.43

 

97.46

 

95.27

 

95.56

 

93.21

 

 

 

NGL, per barrel

 

39.70

 

51.86

 

53.68

 

65.21

 

40.81

 

56.77

 

47.07

 

 

 

Natural gas, per thousand cubic feet

 

3.61

 

3.96

 

8.18

 

2.61

 

3.71

 

5.87

 

4.68

 

 

 

Bitumen, per barrel

 

-

 

62.68

 

-

 

-

 

-

 

-

 

62.68

 

 

 

Synthetic oil, per barrel

 

-

 

89.76

 

-

 

-

 

-

 

-

 

89.76

 

 

Average production costs, per oil-equivalent barrel - total

13.35

 

33.03

 

22.29

 

12.58

 

8.64

 

11.05

 

15.94

 

 

Average production costs, per barrel - bitumen

 

-

 

32.66

 

-

 

-

 

-

 

-

 

32.66

 

 

Average production costs, per barrel - synthetic oil

 

-

 

55.32

 

-

 

-

 

-

 

-

 

55.32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

91.24

 

-

 

88.68

 

-

 

93.42

 

-

 

92.89

 

 

 

NGL, per barrel

 

38.77

 

-

 

-

 

-

 

65.31

 

-

 

64.41

 

 

 

Natural gas, per thousand cubic feet

 

4.54

 

-

 

8.28

 

-

 

10.00

 

-

 

9.38

 

 

Average production costs, per oil-equivalent barrel - total

24.34

 

-

 

6.10

 

-

 

1.85

 

-

 

4.22

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

85.23

 

86.46

 

96.17

 

97.46

 

94.44

 

95.56

 

93.15

 

 

 

NGL, per barrel

 

39.68

 

51.86

 

53.68

 

65.21

 

58.52

 

56.77

 

51.84

 

 

 

Natural gas, per thousand cubic feet

 

3.62

 

3.96

 

8.23

 

2.61

 

8.36

 

5.87

 

6.64

 

 

 

Bitumen, per barrel

 

-

 

62.68

 

-

 

-

 

-

 

-

 

62.68

 

 

 

Synthetic oil, per barrel

 

-

 

89.76

 

-

 

-

 

-

 

-

 

89.76

 

 

Average production costs, per oil-equivalent barrel - total

14.10

 

33.03

 

15.59

 

12.58

 

4.44

 

11.05

 

12.55

 

 

Average production costs, per barrel - bitumen

 

-

 

32.66

 

-

 

-

 

-

 

-

 

32.66

 

 

Average production costs, per barrel - synthetic oil

 

-

 

55.32

 

-

 

-

 

-

 

-

 

55.32

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2013

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

93.56

 

98.91

 

106.75

 

108.73

 

106.18

 

107.92

 

104.13

 

 

 

NGL, per barrel

 

44.30

 

44.96

 

65.36

 

75.24

 

40.83

 

59.55

 

51.12

 

 

 

Natural gas, per thousand cubic feet

 

2.99

 

2.80

 

10.07

 

2.79

 

4.10

 

4.20

 

4.60

 

 

 

Bitumen, per barrel

 

-

 

59.63

 

-

 

-

 

-

 

-

 

59.63

 

 

 

Synthetic oil, per barrel

 

-

 

93.96

 

-

 

-

 

-

 

-

 

93.96

 

 

Average production costs, per oil-equivalent barrel - total

12.02

 

32.02

 

19.57

 

13.95

 

8.95

 

16.81

 

15.42

 

 

Average production costs, per barrel - bitumen

 

-

 

34.30

 

-

 

-

 

-

 

-

 

34.30

 

 

Average production costs, per barrel - synthetic oil

 

-

 

50.94

 

-

 

-

 

-

 

-

 

50.94

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

102.24

 

-

 

99.26

 

-

 

103.96

 

-

 

103.66

 

 

 

NGL, per barrel

 

42.02

 

-

 

-

 

-

 

70.90

 

-

 

69.96

 

 

 

Natural gas, per thousand cubic feet

 

4.37

 

-

 

9.28

 

-

 

10.19

 

-

 

9.82

 

 

Average production costs, per oil-equivalent barrel - total

22.77

 

-

 

3.79

 

-

 

1.87

 

-

 

3.36

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

95.11

 

98.91

 

106.49

 

108.73

 

104.98

 

107.92

 

104.01

 

 

 

NGL, per barrel

 

44.24

 

44.96

 

65.36

 

75.24

 

61.64

 

59.55

 

56.26

 

 

 

Natural gas, per thousand cubic feet

 

3.00

 

2.80

 

9.59

 

2.79

 

8.53

 

4.20

 

6.86

 

 

 

Bitumen, per barrel

 

-

 

59.63

 

-

 

-

 

-

 

-

 

59.63

 

 

 

Synthetic oil, per barrel

 

-

 

93.96

 

-

 

-

 

-

 

-

 

93.96

 

 

Average production costs, per oil-equivalent barrel - total

12.72

 

32.02

 

12.42

 

13.95

 

4.41

 

16.81

 

11.48

 

 

Average production costs, per barrel - bitumen

 

-

 

34.30

 

-

 

-

 

-

 

-

 

34.30

 

 

Average production costs, per barrel - synthetic oil

 

-

 

50.94

 

-

 

-

 

-

 

-

 

50.94

9 


 

 

 

 

 

 

United

 

Canada/

 

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

S. America

Europe

 

Africa

 

Asia

 

Oceania

 

Total

During 2012

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

94.71

 

98.67

 

110.91

 

111.19

 

109.95

 

112.12

 

107.05

 

 

 

NGL, per barrel

 

50.32

 

57.84

 

68.08

 

76.63

 

43.65

 

56.85

 

54.71

 

 

 

Natural gas, per thousand cubic feet

 

2.15

 

1.98

 

8.92

 

2.77

 

3.91

 

4.39

 

3.90

 

 

 

Bitumen, per barrel

 

-

 

58.91

 

-

 

-

 

-

 

-

 

58.91

 

 

 

Synthetic oil, per barrel

 

-

 

92.77

 

-

 

-

 

-

 

-

 

92.77

 

 

Average production costs, per oil-equivalent barrel - total

11.14

 

26.94

 

15.06

 

13.35

 

7.27

 

12.11

 

13.02

 

 

Average production costs, per barrel - bitumen

 

-

 

23.71

 

-

 

-

 

-

 

-

 

23.71

 

 

Average production costs, per barrel - synthetic oil

 

-

 

47.45

 

-

 

-

 

-

 

-

 

47.45

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

105.02

 

-

 

104.59

 

-

 

106.59

 

-

 

106.33

 

 

 

NGL, per barrel

 

58.38

 

-

 

-

 

-

 

75.24

 

-

 

74.87

 

 

 

Natural gas, per thousand cubic feet

 

3.22

 

-

 

9.66

 

-

 

9.38

 

-

 

9.48

 

 

Average production costs, per oil-equivalent barrel - total

20.15

 

-

 

3.36

 

-

 

1.43

 

-

 

2.80

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

96.60

 

98.67

 

110.74

 

111.19

 

108.22

 

112.12

 

106.88

 

 

 

NGL, per barrel

 

50.46

 

57.84

 

68.08

 

76.63

 

62.61

 

56.85

 

59.74

 

 

 

Natural gas, per thousand cubic feet

 

2.15

 

1.98

 

9.33

 

2.77

 

7.64

 

4.39

 

6.11

 

 

 

Bitumen, per barrel

 

-

 

58.91

 

-

 

-

 

-

 

-

 

58.91

 

 

 

Synthetic oil, per barrel

 

-

 

92.77

 

-

 

-

 

-

 

-

 

92.77

 

 

Average production costs, per oil-equivalent barrel - total

11.68

 

26.94

 

10.34

 

13.35

 

3.74

 

12.11

 

9.91

 

 

Average production costs, per barrel - bitumen

 

-

 

23.71

 

-

 

-

 

-

 

-

 

23.71

 

 

Average production costs, per barrel - synthetic oil

 

-

 

47.45

 

-

 

-

 

-

 

-

 

47.45

 

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

10 


 

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

Net Productive Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

3

 

8

 

7

 

 

Canada/South America

 

3

 

4

 

2

 

 

Europe

 

1

 

-

 

1

 

 

Africa

 

2

 

2

 

2

 

 

Asia

 

-

 

-

 

1

 

 

Australia/Oceania

 

-

 

-

 

2

 

 

 

Total Consolidated Subsidiaries

 

9

 

14

 

15

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

2

 

1

 

1

 

 

Asia

 

-

 

1

 

-

 

 

 

Total Equity Companies

 

2

 

2

 

1

Total productive exploratory wells drilled

 

11

 

16

 

16

 

 

 

 

 

 

 

 

 

 

Net Dry Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

2

 

2

 

2

 

 

Canada/South America

 

1

 

4

 

-

 

 

Europe

 

1

 

1

 

2

 

 

Africa

 

1

 

-

 

-

 

 

Asia

 

-

 

-

 

2

 

 

Australia/Oceania

 

-

 

-

 

1

 

 

 

Total Consolidated Subsidiaries

 

5

 

7

 

7

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

2

 

1

 

-

 

 

Europe

 

-

 

-

 

1

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

2

 

1

 

1

Total dry exploratory wells drilled

 

7

 

8

 

8

11 


 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

 

 

 

 

 

 

Net Productive Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

721

 

755

 

867

 

 

Canada/South America

 

178

 

201

 

73

 

 

Europe

 

8

 

13

 

10

 

 

Africa

 

41

 

33

 

39

 

 

Asia

 

19

 

30

 

28

 

 

Australia/Oceania

 

5

 

3

 

-

 

 

 

Total Consolidated Subsidiaries

 

972

 

1,035

 

1,017

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

340

 

328

 

282

 

 

Europe

 

2

 

2

 

4

 

 

Asia

 

1

 

8

 

7

 

 

 

Total Equity Companies

 

343

 

338

 

293

Total productive development wells drilled

 

1,315

 

1,373

 

1,310

 

 

 

 

 

 

 

 

 

 

Net Dry Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

6

 

5

 

5

 

 

Canada/South America

 

3

 

-

 

-

 

 

Europe

 

1

 

2

 

1

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

-

 

2

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

10

 

7

 

8

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

1

 

1

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

1

 

1

 

-

Total dry development wells drilled

 

11

 

8

 

8

 

 

 

 

 

 

 

 

 

 

 

Total number of net wells drilled

 

1,344

 

1,405

 

1,342

12 


 

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

Syncrude Operations. Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2014, the company’s share of net production of synthetic crude oil was about 60 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project. The Kearl project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 48 thousand acres in the Athabasca oil sands deposit.

The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment train. The product, a blend of bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline. During 2014, average net production at Kearl was 66 thousand barrels per day. The Kearl Expansion project was essentially complete at the end of 2014, and the commissioning of facilities commenced in preparation for start-up.

 

5. Present Activities

A. Wells Drilling

 

 

 

 

Year-End 2014

 

Year-End 2013

 

 

 

 

Gross

 

Net

 

Gross

 

Net

Wells Drilling

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,120

 

442

 

1,199

 

480

 

 

Canada/South America

35

 

29

 

107

 

95

 

 

Europe

18

 

8

 

29

 

10

 

 

Africa

33

 

12

 

38

 

11

 

 

Asia

90

 

26

 

112

 

32

 

 

Australia/Oceania

10

 

4

 

18

 

5

 

 

 

Total Consolidated Subsidiaries

1,306

 

521

 

1,503

 

633

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

31

 

6

 

9

 

4

 

 

Europe

4

 

1

 

8

 

3

 

 

Asia

1

 

-

 

11

 

1

 

 

 

Total Equity Companies

36

 

7

 

28

 

8

Total gross and net wells drilling

1,342

 

528

 

1,531

 

641

 

B. Review of Principal Ongoing Activities

UNITED STATES

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

During the year, 1,048.3 net exploration and development wells were completed in the inland lower 48 states. Development activities focused on liquids-rich opportunities in the onshore U.S., primarily in the Permian Basin of West Texas and New Mexico, the Bakken oil play in North Dakota and Montana, and the Woodford and Caney Shales in the Ardmore and Marietta basins of Oklahoma. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia, the Utica Shale of Ohio, the Haynesville Shale of Texas and Louisiana, the Barnett Shale of North Texas, and the Fayetteville Shale of Arkansas.

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

13 


 

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

CANADA / SOUTH AMERICA  

Canada

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

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

Argentina

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

EUROPE

Germany

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

Netherlands

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

Norway

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

United Kingdom

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

AFRICA

Angola

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

Chad

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

Equatorial Guinea

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

Nigeria

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

14 


 

ASIA

Azerbaijan

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

Indonesia

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

Iraq

At year-end 2014, ExxonMobil’s onshore acreage was 0.7 million net acres. A total of 3.0 net development wells were completed at the West Qurna Phase I oil field during the year. Field rehabilitation activities continued during 2014 and across the life of this project will include drilling of new wells, working over of existing wells, and optimization and debottlenecking of existing facilities. In the Kurdistan Region of Iraq, ExxonMobil continued its seismic program and exploration drilling until operations were temporarily suspended due to security concerns in the region.  

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2014. A total of 1.2 net development wells were completed during 2014. Following a brief production period in 2013, Kashagan operations were suspended due to a leak in the onshore section of the gas pipeline. Working with our partners, activities are under way to replace both the oil and gas pipelines.  

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.2 million net acres offshore at year-end 2014. During the year, a total of 4.5 net development wells were completed. The Tapis Enhanced Oil Recovery and Damar projects started up in 2014.  

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2014. During the year, a total of 0.3 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas capacity and 2.0 billion cubic feet per day of flowing gas capacity at year end. Development activities continued on the Barzan project.

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2014.

 

Russia

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

     At year-end 2014, ExxonMobil’s net acreage in the Rosneft joint venture agreements for the Kara, Laptev, Chukchi and Black Seas was 63.6 million acres, all offshore. ExxonMobil and Rosneft formed a joint venture to evaluate the development of tight-oil reserves in western Siberia in 2013. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.

 

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2014.

 

 

 

 

15 


 

 

United Arab Emirates

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

ExxonMobil’s onshore oil concession expired in January 2014.

AUSTRALIA / OCEANIA

Australia

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

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2014. The project consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.

Papua New Guinea

A total of 1.1 million net onshore acres were held by ExxonMobil at year-end 2014, with 1.6 net development wells completed during the year. The Papua New Guinea (PNG) LNG project started up in 2014. The PNG LNG integrated development includes gas production and processing facilities in the southern PNG Highlands, a 6.9 million tonnes per year LNG facility near Port Moresby and approximately 434 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2014, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 33.4 million net acres were held at year-end 2014 and 3.8 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 18 million barrels of oil and 2,800 billion cubic feet of natural gas for the period from 2015 through 2017. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

16 


 

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

A. Gross and Net Productive Wells

 

 

 

 

 

Year-End 2014

 

Year-End 2013

 

 

 

 

Oil

Gas

 

Oil

Gas

 

 

 

 

Gross

Net

Gross

Net

 

Gross

Net

Gross

Net

Gross and Net Productive Wells

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

24,242

9,249

36,095

21,571

 

23,395

8,487

38,392

23,839

 

 

Canada/South America

5,012

4,659

4,577

1,782

 

5,486

4,990

4,478

1,762

 

 

Europe

1,215

347

642

259

 

1,254

352

649

269

 

 

Africa

1,299

513

19

8

 

1,186

472

16

6

 

 

Asia

804

267

207

150

 

756

270

207

151

 

 

Australia/Oceania

669

157

43

21

 

661

147

38

19

 

 

 

Total Consolidated Subsidiaries

33,241

15,192

41,583

23,791

 

32,738

14,718

43,780

26,046

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

14,571

5,605

4,365

494

 

14,362

5,529

4,369

496

 

 

Europe

57

20

567

179

 

49

17

555

173

 

 

Asia

110

27

125

30

 

1,329

143

122

29

 

 

 

Total Equity Companies

14,738

5,652

5,057

703

 

15,740

5,689

5,046

698

Total gross and net productive wells

47,979

20,844

46,640

24,494

 

48,478

20,407

48,826

26,744

 

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

.

  

17 


 

B. Gross and Net Developed Acreage   

 

 

 

 

Year-End 2014

 

Year-End 2013

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Developed Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

14,777

 

9,367

 

16,504

 

10,061

 

 

Canada/South America (1) 

3,515

 

2,242

 

3,413

 

2,041

 

 

Europe

3,337

 

1,506

 

3,355

 

1,511

 

 

Africa

2,286

 

815

 

2,105

 

780

 

 

Asia

1,817

 

551

 

1,828

 

557

 

 

Australia/Oceania

2,123

 

758

 

2,123

 

758

 

 

 

Total Consolidated Subsidiaries

27,855

 

15,239

 

29,328

 

15,708

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

949

 

208

 

968

 

241

 

 

Europe

4,342

 

1,356

 

4,341

 

1,356

 

 

Asia

628

 

156

 

5,731

 

640

 

 

 

Total Equity Companies

5,919

 

1,720

 

11,040

 

2,237

Total gross and net developed acreage

33,774

 

16,959

 

40,368

 

17,945

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

Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.

 

C. Gross and Net Undeveloped Acreage

 

 

 

 

Year-End 2014

 

Year-End 2013

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Undeveloped Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

10,262

 

4,894

 

7,645

 

4,722

 

 

Canada/South America (1) 

16,100

 

12,250

 

16,267

 

9,232

 

 

Europe

10,601

 

5,636

 

13,461

 

6,585

 

 

Africa

22,143

 

15,020

 

20,877

 

13,446

 

 

Asia

17,437

 

13,016

 

18,639

 

13,979

 

 

Australia/Oceania

6,653

 

2,013

 

7,144

 

1,991

 

 

 

Total Consolidated Subsidiaries

83,196

 

52,829

 

84,033

 

49,955

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

350

 

118

 

363

 

121

 

 

Europe

-

 

-

 

-

 

-

 

 

Asia

191,146

 

63,632

 

34,147

 

11,352

 

 

 

Total Equity Companies

191,496

 

63,750

 

34,510

 

11,473

Total gross and net undeveloped acreage

274,692

 

116,579

 

118,543

 

61,428

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

 

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

  

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

18 


 

D. Summary of Acreage Terms

UNITED STATES

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

CANADA / SOUTH AMERICA

Canada

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

Argentina

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

EUROPE

Germany

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years each. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license.

Netherlands

Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the license and are based on the Mining Law.

Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.

Norway

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997, have an initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.

 

19 


 

United Kingdom

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

AFRICA

Angola

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

Chad

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

Equatorial Guinea

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

Nigeria

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase that can be divided into multiple optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.

Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years, while in all other areas the licenses are for five years. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.

OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. Commercial terms applicable to the existing joint venture oil production are defined by the Petroleum Profits Tax Act.

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

 

20 


 

 ASIA  

Azerbaijan

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

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

Indonesia

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract (PSC), negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. In 2012, Indonesia’s Constitutional Court ruled certain articles of law relating to BPMIGAS to be unconstitutional, but stated that all existing PSCs signed with BPMIGAS should remain in force until their expiry, and the functions and duties previously performed by BPMIGAS are to be carried out by the relevant Ministry of the Government of Indonesia until the promulgation of a new oil and gas law. By presidential decree, SKKMIGAS became the interim successor to BPMIGAS. The current PSCs have an exploration period of six years, which can be extended up to 10 years, and an exploitation period of 20 years. PSCs generally require the contractor to relinquish 10 percent to 20 percent of the contract area after three years and generally allow the contractor to retain no more than 50 percent to 80 percent of the original contract area after six years, depending on the acreage and terms.

Iraq

Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with South Oil Company of the Iraqi Ministry of Oil for the rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for five years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.

Exploration and production activities in the Kurdistan Region of Iraq are governed by production sharing contracts negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years with the possibility of two-year extensions. The production period is 20 years with the right to extend for five years.

Kazakhstan

Onshore exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.

Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

Malaysia

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

Qatar

The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.

Republic of Yemen

The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which was made in June 1995.

 

21 


 

 Russia  

Terms for ExxonMobil’s Sakhalin acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in ten-year increments as specified in the PSA.

Exploration and production activities in the Kara, Laptev, Chukchi and Black Seas are governed by joint venture agreements concluded with Rosneft in 2013 and 2014 that cover certain of Rosneft’s offshore licenses. The Kara Sea licenses covered by the joint venture agreements concluded in 2013 extend through 2040 and include an exploration period through 2020. Additional licenses in the Kara, Laptev and Chukchi Seas covered by the joint venture agreements concluded in 2014 extend through 2043 and include an exploration period through 2023. The Kara, Laptev and Chukchi Sea licenses require development plan submission within eight years of a discovery and development activities within five years of plan approval. The Black Sea exploration license extends through 2017 and a discovery is the basis for obtaining a license for production. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.

Thailand

The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a ten-year extension at terms generally prevalent at the time.

United Arab Emirates

Exploration and production activities for the major onshore oil fields in the Emirate of Abu Dhabi were governed by a 75-year oil concession agreement executed in 1939, which expired in January 2014. An interest in the development and production activities of the Upper Zakum field, a major offshore field, was acquired effective as of January 2006, for a term expiring March 2026, and in 2013 the governing agreements were extended to 2041.

AUSTRALIA/OCEANIA

Australia

Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for the life of the field. Effective from July 1998, new production licenses are granted “indefinitely”. In each case, a production license may be terminated if no production operations have been carried on for five years.

Papua New Guinea

Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially viable within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. Extensions of Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.

22 


 

Information with regard to the Downstream segment follows:

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

Refining Capacity At Year-End 2014 (1)

 

 

 

 

ExxonMobil

ExxonMobil

 

 

 

 

Share  KBD (2) 

Interest %

United States

 

 

 

 

 

 

Torrance

California

150

 

100

 

 

Joliet

Illinois

238

 

100

 

 

Baton Rouge

Louisiana

502

 

100

 

 

Baytown

Texas

561

 

100

 

 

Beaumont

Texas

345

 

100

 

 

Other (2 refineries)

 

155

 

 

 

 

 

 Total United States

 

1,951

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

Strathcona

Alberta

189

 

69.6

 

 

Nanticoke

Ontario

113

 

69.6

 

 

Sarnia

Ontario

119

 

69.6

 

 

 

Total Canada

 

421

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

Antwerp

Belgium

307

 

100

 

 

Fos-sur-Mer

France

133

 

82.9

 

 

Gravenchon

France

236

 

82.9

 

 

Karlsruhe

Germany

78

 

25

 

 

Augusta

Italy

198

 

100

 

 

Trecate

Italy

127

 

74.9

 

 

Rotterdam

Netherlands

191

 

100

 

 

Slagen

Norway

116

 

100

 

 

Fawley

United Kingdom

260

 

100

 

 

 

Total Europe

 

1,646

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

Jurong/PAC

Singapore

592

 

100

 

 

Sriracha

Thailand

167

 

66

 

 

Other (7 refineries)

 

256

 

 

 

 

 

Total Asia Pacific

 

1,015

 

 

 

 

 

 

 

 

 

 

 

Other Non-U.S.

 

 

 

 

 

 

Yanbu

Saudi Arabia

200

 

50

 

 

Laffan

Qatar

15

 

10

 

 

 

Total Other Non-U.S.

 

215

 

 

 

Total Worldwide

 

5,248

 

 

 

 

(1)   Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time.

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

23 


 

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

Retail Sites At Year-End 2014

 

 

United States

 

 

 

 

Owned/leased

 -  

 

 

 

Distributors/resellers

9,436

 

 

 

 

Total United States

9,436

 

 

 

 

 

 

 

 

Canada

 

 

 

 

Owned/leased

473

 

 

 

Distributors/resellers

1,256

 

 

 

 

Total Canada

1,729

 

 

 

 

 

 

 

 

Europe

 

 

 

 

Owned/leased

3,209

 

 

 

Distributors/resellers

3,049

 

 

 

 

Total Europe

6,258

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

Owned/leased

653

 

 

 

Distributors/resellers

757

 

 

 

 

Total Asia Pacific

1,410

 

 

 

 

 

 

 

 

Latin America

 

 

 

 

Owned/leased

15

 

 

 

Distributors/resellers

734

 

 

 

 

Total Latin America

749

 

 

 

 

 

 

 

 

Middle East/Africa

 

 

 

 

Owned/leased

404

 

 

 

Distributors/resellers

231

 

 

 

 

Total Middle East/Africa

635

 

 

 

 

 

 

 

 

Worldwide

 

 

 

 

Owned/leased

4,754

 

 

 

Distributors/resellers

15,463

 

 

 

 

Total Worldwide

20,217

 

24 


 

Information with regard to the Chemical segment follows:

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

Chemical Complex Capacity At Year-End 2014 (1)(2)  

 

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil

 

 

 

 

Ethylene

Polyethylene

Polypropylene

Paraxylene

Interest %

North America

 

 

 

 

 

 

 

 

 

 

 

 

Baton Rouge

Louisiana

1.0

 

1.3

 

0.4

 

-

 

100

 

 

Baytown

Texas

2.2

 

-

 

0.7

 

0.6

 

100

 

 

Beaumont

Texas

0.9

 

1.0

 

-

 

0.3

 

100

 

 

Mont Belvieu

Texas

-

 

1.0

 

-

 

-

 

100

 

 

Sarnia

Ontario

0.3

 

0.5

 

-

 

-

 

69.6

 

 

 

Total North America

 

4.4

 

3.8

 

1.1

 

0.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

 

 

 

 

 

 

Antwerp

Belgium

-

 

0.4

 

-

 

-

 

100

 

 

Fife

United Kingdom

0.4

 

-

 

-

 

-

 

50

 

 

Meerhout

Belgium

-

 

0.5

 

-

 

-

 

100

 

 

Gravenchon

France

0.4

 

0.4

 

0.3

 

-

 

100

 

 

Rotterdam

Netherlands

-

 

-

 

-

 

0.7

 

100

 

 

 

Total Europe

 

0.8

 

1.3

 

0.3

 

0.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Middle East

 

 

 

 

 

 

 

 

 

 

 

 

Al Jubail

Saudi Arabia

0.6

 

0.7

 

-

 

-

 

50

 

 

Yanbu

Saudi Arabia

1.0

 

0.7

 

0.2

 

-

 

50

 

 

 

Total Middle East

 

1.6

 

1.4

 

0.2

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

 

 

 

 

 

 

Fujian

China

0.3

 

0.2

 

0.2

 

0.2

 

25

 

 

Singapore

Singapore

1.9

 

1.9

 

0.9

 

1.0

 

100

 

 

Sriracha

Thailand

-

 

-

 

-

 

0.5

 

66

 

 

 

Total Asia Pacific

 

2.2

 

2.1

 

1.1

 

1.7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

All Other

 

-

 

-

 

-

 

0.1

 

 

 

Total Worldwide

 

9.0

 

8.6

 

2.7

 

3.4

 

 

 

 

(1)   Capacity for ethylene, polyethylene, polypropylene and paraxylene in millions of metric tons per year.

(2)   Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capacity is ExxonMobil’s interest.

25 


 

Item 3.       Legal Proceedings

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

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

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

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

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

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

Item 4.       MINE SAFETY DISCLOSURES

Not applicable.

 

 

_______________________

 

   

26 


 

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

 

Rex W. Tillerson

Chairman of the Board

 

 

 

 

Held current title since:

January 1, 2006

Age: 62

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

 

Mark W. Albers

Senior Vice President

 

 

 

 

Held current title since:

April 1, 2007

Age: 58

Mr. Mark W. Albers became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.

 

Michael J. Dolan

Senior Vice President

 

 

 

 

Held current title since:

April 1, 2008

Age: 61

Mr. Michael J. Dolan became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.

 

Andrew P. Swiger

Senior Vice President

 

 

 

 

Held current title since:

April 1, 2009

Age: 58

Mr. Andrew P. Swiger became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.

 

Jack P. Williams, Jr.

Senior Vice President

 

 

 

 

Held current title since:

June 1, 2014

Age: 51

Mr. Jack P. Williams, Jr. was Vice President of ExxonMobil Development Company May 1, 2009 – July 1, 2010. He was President of XTO Energy Inc. June 25, 2010 – May 31, 2013. He was Executive Vice President of ExxonMobil Production Company June 1, 2013 – June 30, 2014. He became Senior Vice President of Exxon Mobil Corporation on June 1, 2014, a position he still holds as of this filing date.

 

Darren W. Woods

Senior Vice President 

 

 

 

 

Held current title since:

June 1, 2014

Age: 50

Mr. Darren W. Woods was Director, Refining Europe/Africa/Middle East, ExxonMobil Refining & Supply Company     February 1, 2008 – June 30, 2010. He was Vice President, Supply & Transportation, ExxonMobil Refining & Supply Company July 1, 2010 – July 31, 2012. He was President of ExxonMobil Refining & Supply Company August 1, 2012 – July 31, 2014 and Vice President of Exxon Mobil Corporation August 1, 2012 – May 31, 2014. He became Senior Vice President of Exxon Mobil Corporation on June 1, 2014, a position he still holds as of this filing date.

 

S. Jack Balagia

Vice President and General Counsel

 

 

 

 

Held current title since:

March 1, 2010

Age: 63

Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 – March 1, 2010. He became Vice President and General Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.

 

 

  

27 


 

Neil A. Chapman

Vice President

 

 

 

 

Held current title since:

January 1, 2015

Age: 52

Mr. Neil A. Chapman was President of ExxonMobil Global Services Company April 4, 2007 – March 31, 2011. He was Senior Vice President, ExxonMobil Chemical Company April 1, 2011 – December 31, 2014. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on January 1, 2015, positions he still holds as of this filing date.

 

Randy J. Cleveland

President, XTO Energy Inc., a subsidiary of the Corporation

 

 

 

Held current title since:

June 1, 2013

Age: 53

Mr. Randy J. Cleveland was Planning & Commercial Manager, ExxonMobil Production Company May 1, 2009 – June 24, 2010. He was Vice President, XTO Integration, XTO Energy Inc. June 25, 2010 – January 31, 2012. He was Executive Vice President, XTO Energy Inc. February 1, 2012 – May 31, 2013. He became President of XTO Energy Inc. on June 1, 2013, a position he still holds as of this filing date.

 

William M. Colton

Vice President – Corporate Strategic Planning

 

 

 

 

Held current title since:

February 1, 2009

Age: 61

Mr. William M. Colton became Vice President – Corporate Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.

 

Michael G. Cousins

Vice President

 

 

 

Held current title since:

March 1, 2013

Age: 54

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

 

Neil W. Duffin

President, ExxonMobil Development Company 

 

 

 

Held current title since:

April 13, 2007

Age: 58

Mr. Neil W. Duffin became President of ExxonMobil Development Company on April 13, 2007, a position he still holds as of this filing date.

 

Robert S. Franklin

Vice President

 

 

 

 

Held current title since:

May 1, 2009

Age: 57

Mr. Robert S. Franklin was President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation May 1, 2009 – February 28, 2013. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date.

 

Stephen M. Greenlee

Vice President

 

 

 

 

Held current title since:

September 1, 2010

Age: 57

Mr. Stephen M. Greenlee was President of ExxonMobil Upstream Research Company June 1, 2009 – August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.

 

 

 

  

28 


 

Alan J. Kelly

Vice President

 

 

 

 

Held current title since:

December 1, 2007

Age: 57

Mr. Alan J. Kelly became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporation on December 1, 2007. On February 1, 2012, the businesses of ExxonMobil Lubricants & Petroleum Specialties Company and ExxonMobil Fuels Marketing Company were consolidated and Mr. Kelly became President of the combined ExxonMobil Fuels, Lubricants & Specialties Marketing Company and Vice President of Exxon Mobil Corporation, positions he still holds as of this filing date.

 

David S. Rosenthal

Vice President and Controller

 

 

 

Held current title since:

October 1, 2008 (Vice President)

September 1, 2014 (Controller)

Age: 58

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

 

Robert N. Schleckser

Vice President and Treasurer

 

 

 

 

Held current title since:

May 1, 2011

Age: 58

Mr. Robert N. Schleckser was Assistant Treasurer of Exxon Mobil Corporation February 1, 2009 – April 30, 2011. He became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, positions he still holds as of this filing date.

 

James M. Spellings, Jr.

Vice President and General Tax Counsel

 

 

 

 

Held current title since:

March 1, 2010

Age: 53

Mr. James M. Spellings, Jr. was Associate General Tax Counsel of Exxon Mobil Corporation April 1, 2007 – March 1, 2010. He became Vice President and General Tax Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.

 

Thomas R. Walters

Vice President

 

 

 

 

Held current title since:

April 1, 2009

Age: 60

Mr. Thomas R. Walters was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation April 1, 2009 – February 28, 2013. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on March 1, 2013, positions he still holds as of this filing date.

 

Dennis G. Wascom

Vice President

 

 

 

 

Held current title since:

August 1, 2014

Age: 58

Mr. Dennis G. Wascom was Director, Refining Americas, ExxonMobil Refining & Supply Company April 1, 2009 – June 30, 2013. He was Director, Refining North America, ExxonMobil Refining & Supply Company July 1, 2013 – July 31, 2014. He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on August 1, 2014, positions he still holds as of this filing date.

 

Jeffrey J. Woodbury

Vice President – Investor Relations and Secretary

 

 

 

Held current title since:

July 1, 2011 (Vice President)

September 1, 2014 (Secretary)

Age: 54

Mr. Jeffrey J. Woodbury was Executive Vice President of ExxonMobil Development Company April 1, 2009 – June 30, 2011. He was Vice President, Safety, Security, Health and Environment of Exxon Mobil Corporation July 1, 2011 – August 31, 2014. He became Vice President – Investor Relations and Secretary of Exxon Mobil Corporation on September 1, 2014, positions he still holds as of this filing date.

 

 

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

29 


 

PART II

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

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

 

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2014

 

 

 

 

Total Number of

 

 

 

 

 

Shares

 

 

 

 

 

Purchased as

Maximum Number

 

 

 

 

Part of Publicly

of Shares that May

 

 

Total Number of

Average Price

Announced

Yet Be Purchased

 

 

Shares

Paid per

Plans or

Under the Plans or

Period

Purchased

Share

Programs

Programs

October 2014

11,934,362

93.06

11,934,362

 

November 2014

9,803,071

95.42

9,803,071

 

December 2014

13,899,727

91.55

13,899,727

 

 

Total

35,637,160

93.12

35,637,160

(See note 1)

 

Note 1 - On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated February 2, 2015, the Corporation stated that first quarter 2015 share purchases to reduce shares outstanding are anticipated to equal $1 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

Item 6.       Selected Financial Data

 

 

 

Years Ended December 31,

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

 

(millions of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue (1) 

 

394,105

 

420,836

 

451,509

 

467,029

 

370,125

          (1) Sales-based taxes included

 

29,342

 

30,589

 

32,409

 

33,503

 

28,547

Net income attributable to ExxonMobil

 

32,520

 

32,580

 

44,880

 

41,060

 

30,460

Earnings per common share

 

7.60

 

7.37

 

9.70

 

8.43

 

6.24

Earnings per common share - assuming dilution

 

7.60

 

7.37

 

9.70

 

8.42

 

6.22

Cash dividends per common share

 

2.70

 

2.46

 

2.18

 

1.85

 

1.74

Total assets

 

349,493

 

346,808

 

333,795

 

331,052

 

302,510

Long-term debt

 

11,653

 

6,891

 

7,928

 

9,322

 

12,227

 

 

 

 

 

 

 

 

 

 

 

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

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

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

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

30 


 

Item 8.       Financial Statements and Supplementary Data

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

·           

Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 25, 2015, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 19: Income, Sales-Based and Other Taxes”;

·           

“Quarterly Information” (unaudited);

·           

“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and

·           

“Frequently Used Terms” (unaudited).

Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

Item 9.       Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2014. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Management’s Report on Internal Control Over Financial Reporting

Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2014.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014, as stated in their report included in the Financial Section of this report.

Changes in Internal Control Over Financial Reporting

There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.

Item 9B.     Other Information

None.

31 


 

PART III

Item 10.     Directors, Executive Officers and Corporate Governance

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2015 annual meeting of shareholders (the “2015 Proxy Statement”):

·           

The section entitled “Election of Directors”;

·           

The portion entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of the section entitled “Director and Executive Officer Stock Ownership”;

·           

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

·           

The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Meeting Attendance” of the section entitled “Corporate Governance”.

  

Item 11.     Executive Compensation

Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the registrant’s 2015 Proxy Statement.

Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Director and Executive Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 2015 Proxy Statement.

 

Equity Compensation Plan Information

 

 

(a)

 

(b)

 

(c)

 

 

 

 

 

 

 

Number of Securities

 

 

 

 

 

Weighted-

 

Remaining Available

 

 

 

 

 

Average

 

for Future Issuance

 

 

Number of Securities

 

Exercise Price

 

 Under Equity

 

 

 to be Issued Upon

 

of Outstanding

 

 Compensation 

 

 

Exercise of

 

Options,

 

Plans [Excluding

 

 

Outstanding Options,

 

Warrants and

 

Securities Reflected

Plan Category

Warrants and Rights

 

Rights

 

in Column (a)]

 

 

 

 

 

 

 

 

 

Equity compensation plans approved by security holders

24,243,615

(1)

 

-

 

109,066,057

(2)(3)

 

 

 

 

 

 

 

 

 

Equity compensation plans not approved by security holders

-

 

 

-

 

-

 

 

 

 

 

 

 

 

 

 

 

Total

24,243,615

 

 

-

 

109,066,057

 

 

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

(2)   Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 108,454,857 shares available for award under the 2003 Incentive Program and 611,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

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

32 


 

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

Incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 2015 Proxy Statement.

Item 14.     Principal Accounting Fees and Services

Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2015 Proxy Statement.

 

PART IV

Item 15.     Exhibits, Financial Statement Schedules

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

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

(a)       (3) Exhibits:

           See Index to Exhibits of this report.

33 


 

FINANCIAL SECTION

 

 

TABLE OF CONTENTS

 

 

 

Business Profile

35

 

 

Financial Summary

36

 

 

Frequently Used Terms

37

 

 

Quarterly Information

39

 

 

Management’s Discussion and Analysis of Financial Condition

and Results of Operations

 

 

 

Functional Earnings

40

 

 

Forward-Looking Statements

41

 

 

Overview

41

 

 

Business Environment and Risk Assessment

41

 

 

Review of 2014 and 2013 Results

44

 

 

Liquidity and Capital Resources

48

 

 

Capital and Exploration Expenditures

53

 

 

Taxes

53

 

 

Environmental Matters

54

 

 

Market Risks, Inflation and Other Uncertainties

54

 

 

Recently Issued Accounting Standards                                                            

56

 

 

Critical Accounting Estimates

56

 

 

Management’s Report on Internal Control Over Financial Reporting

60

 

 

Report of Independent Registered Public Accounting Firm

61

 

 

Consolidated Financial Statements

 

 

 

Statement of Income

62

 

 

Statement of Comprehensive Income

63

 

 

Balance Sheet

64

 

 

Statement of Cash Flows

65

 

 

Statement of Changes in Equity

66

 

 

Notes to Consolidated Financial Statements

 

 

 

  1. Summary of Accounting Policies

67

 

 

  2. Accounting Changes

69

 

 

  3. Miscellaneous Financial Information

69

 

 

  4. Other Comprehensive Income Information

70

 

 

  5. Cash Flow Information

71

 

 

  6. Additional Working Capital Information

71

 

 

  7. Equity Company Information

72

 

 

  8. Investments, Advances and Long-Term Receivables

73

 

 

  9. Property, Plant and Equipment and Asset Retirement Obligations

74

 

 

10. Accounting for Suspended Exploratory Well Costs

75

 

 

11. Leased Facilities

77

 

 

12. Earnings Per Share

77

 

 

13. Financial Instruments and Derivatives

78

 

 

14. Long-Term Debt

79

 

 

15. Incentive Program

80

 

 

16. Litigation and Other Contingencies

81

 

 

17. Pension and Other Postretirement Benefits

83

 

 

18. Disclosures about Segments and Related Information

91

 

 

19. Income, Sales-Based and Other Taxes

94

 

 

Supplemental Information on Oil and Gas Exploration and Production Activities

97

 

 

Operating Summary

112

 

  

34 


BUSINESS PROFILE

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Return on

 

 

Capital and

 

 

 

 

Earnings After

 

Average Capital

 

Average Capital

 

 

Exploration

 

 

 

 

Income Taxes

 

Employed

 

Employed

 

 

Expenditures

Financial

 

2014

 

2013

 

2014

 

2013

 

2014

 

2013

 

 

2014

 

2013

 

 

 

 

(millions of dollars)

 

(percent)

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

5,197

 

4,191

 

62,403

 

59,898

 

8.3

 

7.0

 

 

9,401

 

9,145

 

Non-U.S.

 

22,351

 

22,650

 

102,562

 

93,071

 

21.8

 

24.3

 

 

23,326

 

29,086

 

 

Total

 

27,548

 

26,841

 

164,965

 

152,969

 

16.7

 

17.5

 

 

32,727

 

38,231

Downstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

1,618

 

2,199

 

6,070

 

4,757

 

26.7

 

46.2

 

 

1,310

 

951

 

Non-U.S.

 

1,427

 

1,250

 

17,907

 

19,673

 

8.0

 

6.4

 

 

1,724

 

1,462

 

 

Total

 

3,045

 

3,449

 

23,977

 

24,430

 

12.7

 

14.1

 

 

3,034

 

2,413

Chemical

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

2,804

 

2,755

 

6,121

 

4,872

 

45.8

 

56.5

 

 

1,690

 

963

 

Non-U.S.

 

1,511

 

1,073

 

16,076

 

15,793

 

9.4

 

6.8

 

 

1,051

 

869

 

 

Total

 

4,315

 

3,828

 

22,197

 

20,665

 

19.4

 

18.5

 

 

2,741

 

1,832

Corporate and financing

 

(2,388)

 

(1,538)

 

(8,029)

 

(6,489)

 

-

 

-

 

 

35

 

13

 

 

Total

 

32,520

 

32,580

 

203,110

 

191,575

 

16.2

 

17.2

 

 

38,537

 

42,489

 

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



 

Operating

2014

 

2013

 

 

 

 

2014

 

2013

 

 

(thousands of barrels daily)

 

 

 

(thousands of barrels daily)

Net liquids production

 

 

 

 

Refinery throughput

 

 

 

 

United States

454

 

431

 

 

United States

1,809

 

1,819

 

Non-U.S.

1,657

 

1,771

 

 

Non-U.S.

2,667

 

2,766

 

 

Total

2,111

 

2,202

 

 

 

Total

4,476

 

4,585

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

 

 

(thousands of barrels daily)

Natural gas production available for sale

 

 

 

 

Petroleum product sales

 

 

 

 

United States

3,404

 

3,545

 

 

United States

2,655

 

2,609

 

Non-U.S.

7,741

 

8,291

 

 

Non-U.S.

3,220

 

3,278

 

 

Total

11,145

 

11,836

 

 

 

Total

5,875

 

5,887

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

 

 

(thousands of metric tons)

Oil-equivalent production (1) 

3,969

 

4,175

 

Chemical prime product sales (2)

 

 

 

 

 

 

 

 

 

 

 

United States

9,528

 

9,679

 

 

 

 

 

 

 

 

Non-U.S.

14,707

 

14,384

 

 

 

 

 

 

 

 

 

Total

24,235

 

24,063

 

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

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

  

35 


FINANCIAL SUMMARY

 

 

  

 

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

 

(millions of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue (1) 

 

394,105

 

420,836

 

451,509

 

467,029

 

370,125

Earnings

 

 

 

 

 

 

 

 

 

 

 

Upstream

 

27,548

 

26,841

 

29,895

 

34,439

 

24,097

 

Downstream

 

3,045

 

3,449

 

13,190

 

4,459

 

3,567

 

Chemical

 

4,315

 

3,828

 

3,898

 

4,383

 

4,913

 

Corporate and financing

 

(2,388)

 

(1,538)

 

(2,103)

 

(2,221)

 

(2,117)

 

Net income attributable to ExxonMobil

 

32,520

 

32,580

 

44,880

 

41,060

 

30,460

Earnings per common share

 

7.60

 

7.37

 

9.70

 

8.43

 

6.24

Earnings per common share – assuming dilution

 

7.60

 

7.37

 

9.70

 

8.42

 

6.22

Cash dividends per common share

 

2.70

 

2.46

 

2.18

 

1.85

 

1.74

 

 

 

 

 

 

 

 

 

 

 

 

Earnings to average ExxonMobil share of equity (percent)

 

18.7

 

19.2

 

28.0

 

27.3

 

23.7

 

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

(11,723)

 

(12,416)

 

321

 

(4,542)

 

(3,649)

Ratio of current assets to current liabilities (times)

 

0.82

 

0.83

 

1.01

 

0.94

 

0.94

 

 

 

 

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

34,256

 

37,741

 

35,179

 

33,638

 

74,156

Property, plant and equipment, less allowances

 

252,668

 

243,650

 

226,949

 

214,664

 

199,548

Total assets

 

349,493

 

346,808

 

333,795

 

331,052

 

302,510

 

 

 

 

 

 

 

 

 

 

 

 

Exploration expenses, including dry holes

 

1,669

 

1,976

 

1,840

 

2,081

 

2,144

Research and development costs

 

971

 

1,044

 

1,042

 

1,044

 

1,012

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

11,653

 

6,891

 

7,928

 

9,322

 

12,227

Total debt

 

29,121

 

22,699

 

11,581

 

17,033

 

15,014

Fixed-charge coverage ratio (times)

 

46.9

 

55.7

 

62.4

 

53.4

 

42.2

Debt to capital (percent)

 

13.9

 

11.2

 

6.3

 

9.6

 

9.0

Net debt to capital (percent) (2) 

 

11.9

 

9.1

 

1.2

 

2.6

 

4.5

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil share of equity at year-end

 

174,399

 

174,003

 

165,863

 

154,396

 

146,839

ExxonMobil share of equity per common share

 

41.51

 

40.14

 

36.84

 

32.61

 

29.48

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

 

 

outstanding (millions)

 

4,282

 

4,419

 

4,628

 

4,870

 

4,885

 

 

 

 

 

 

 

 

 

 

 

 

Number of regular employees at year-end (thousands) (3) 

 

75.3

 

75.0

 

76.9

 

82.1

 

83.6

 

 

 

 

 

 

 

 

 

 

 

 

CORS employees not included above (thousands) (4) 

 

8.4

 

9.8

 

11.1

 

17.0

 

20.1

 

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

(2)   Debt net of cash, excluding restricted cash.

(3)   Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.

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

 

36 


FREQUENTLY USED TERMS

 

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

Cash Flow From Operations and Asset Sales

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

 

Cash flow from operations and asset sales

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

45,116

 

44,914

 

56,170

Proceeds associated with sales of subsidiaries, property, plant and equipment,

 

 

 

 

 

 

 

and sales and returns of investments

 

4,035

 

2,707

 

7,655

 

Cash flow from operations and asset sales

 

49,151

 

47,621

 

63,825

 

Capital Employed

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

 

Capital employed

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

Business uses: asset and liability perspective

 

 

 

 

 

 

Total assets

 

349,493

 

346,808

 

333,795

Less liabilities and noncontrolling interests share of assets and liabilities

 

 

 

 

 

 

 

Total current liabilities excluding notes and loans payable

 

(47,165)

 

(55,916)

 

(60,486)

 

Total long-term liabilities excluding long-term debt

 

(92,143)

 

(87,698)

 

(90,068)

 

Noncontrolling interests share of assets and liabilities

 

(9,099)

 

(8,935)

 

(6,235)

Add ExxonMobil share of debt-financed equity company net assets

 

4,766

 

6,109

 

5,775

 

Total capital employed

 

205,852

 

200,368

 

182,781

 

 

 

 

 

 

 

 

Total corporate sources: debt and equity perspective

 

 

 

 

 

 

Notes and loans payable

 

17,468

 

15,808

 

3,653

Long-term debt

 

11,653

 

6,891

 

7,928

ExxonMobil share of equity

 

174,399

 

174,003

 

165,863

Less noncontrolling interests share of total debt

 

(2,434)

 

(2,443)

 

(438)

Add ExxonMobil share of equity company debt

 

4,766

 

6,109

 

5,775

 

Total capital employed

 

205,852

 

200,368

 

182,781

37 


FREQUENTLY USED TERMS

 

Return on Average Capital Employed

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

 

Return on average capital employed

 

2014

 

2013

 

2012

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income attributable to ExxonMobil

 

32,520

 

32,580

 

44,880

Financing costs (after tax)

 

 

 

 

 

 

 

Gross third-party debt

 

(140)

 

(163)

 

(401)

 

ExxonMobil share of equity companies

 

(256)

 

(239)

 

(257)

 

All other financing costs – net

 

(68)

 

83

 

100

 

 

Total financing costs

 

(464)

 

(319)

 

(558)

 

 

 

Earnings excluding financing costs

 

32,984

 

32,899

 

45,438

 

 

 

 

 

 

 

 

 

 

Average capital employed

 

203,110

 

191,575

 

179,094

 

 

 

 

 

 

 

 

 

 

Return on average capital employed – corporate total

 

16.2%

 

17.2%

 

25.4%

38 


QUARTERLY INFORMATION

 

 

  

 

 

 

 

2014

 

2013

 

 

 

First

Second

Third

Fourth

 

 

First

Second

Third

Fourth

 

 

 

 

Quarter

Quarter

Quarter

Quarter

Year

 

Quarter

Quarter

Quarter

Quarter

Year

Volumes

 

 

 

 

 

 

 

 

 

 

 

 

Production of crude oil

 

(thousands of barrels daily)

 

and natural gas liquids,

 

2,148

2,048

2,065

2,182

2,111

 

2,193

2,182

2,199

2,235

2,202

 

synthetic oil and bitumen

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

 

4,509

4,454

4,591

4,349

4,476

 

4,576

4,466

4,847

4,452

4,585

Petroleum product sales

 

5,817

5,841

5,999

5,845

5,875

 

5,755

5,765

6,031

5,994

5,887

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production

 

(millions of cubic feet daily)

 

available for sale

 

12,016

10,750

10,595

11,234

11,145

 

13,213

11,354

10,914

11,887

11,836

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1) 

 

4,151

3,840

3,831

4,054

3,969

 

4,395

4,074

4,018

4,216

4,175

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of metric tons)

Chemical prime product sales

 

6,128

6,139

6,249

5,719

24,235

 

5,910

5,831

6,245

6,077

24,063

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Summarized financial data

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating

 

(millions of dollars)

 

revenue (2)(3) 

 

101,312

105,719

103,206

83,868

394,105

 

103,378

103,050

108,390

106,018

420,836

Gross profit (4) 

 

29,166

28,746

28,825

23,240

109,977

 

30,083

28,689

30,300

29,901

118,973

Net income attributable to

 

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil

 

9,100

8,780

8,070

6,570

32,520

 

9,500

6,860

7,870

8,350

32,580

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Per share data

 

(dollars per share)

Earnings per common share (5) 

 

2.10

2.05

1.89

1.56

7.60

 

2.12

1.55

1.79

1.91

7.37

Earnings per common share

 

 

 

 

 

 

 

 

 

 

 

 

 

– assuming dilution (5) 

 

2.10

2.05

1.89

1.56

7.60

 

2.12

1.55

1.79

1.91

7.37

Dividends per common share

 

0.63

0.69

0.69

0.69

2.70

 

0.57

0.63

0.63

0.63

2.46

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock prices

 

 

 

 

 

 

 

 

 

 

 

 

 

High

 

101.22

104.61

104.76

97.20

104.76

 

91.93

93.50

95.49

101.74

101.74

 

Low

 

89.25

96.24

93.62

86.19

86.19

 

86.59

85.02

85.61

84.79

84.79

 

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

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

(3)   Includes amounts for sales-based taxes.

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

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

 

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

There were 433,941 registered shareholders of ExxonMobil common stock at December 31, 2014. At January 31, 2015, the registered shareholders of ExxonMobil common stock numbered 432,983.

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

  

 

39 


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

 

 

  

 

FUNCTIONAL EARNINGS

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars, except per share amounts)

Earnings (U.S. GAAP)

 

 

 

 

 

 

Upstream

 

 

 

 

 

 

 

United States

 

5,197

 

4,191

 

3,925

 

Non-U.S.

 

22,351

 

22,650

 

25,970

Downstream

 

 

 

 

 

 

 

United States

 

1,618

 

2,199

 

3,575

 

Non-U.S.

 

1,427

 

1,250

 

9,615

Chemical

 

 

 

 

 

 

 

United States

 

2,804

 

2,755

 

2,220

 

Non-U.S.

 

1,511

 

1,073

 

1,678

Corporate and financing

 

(2,388)

 

(1,538)

 

(2,103)

 

 

Net income attributable to ExxonMobil (U.S. GAAP)

 

32,520

 

32,580

 

44,880

 

 

 

 

 

 

 

 

 

Earnings per common share

 

7.60

 

7.37

 

9.70

Earnings per common share – assuming dilution

 

7.60

 

7.37

 

9.70

 

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

40 


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

 

 

FORWARD-LOOKING STATEMENTS

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

The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

 

OVERVIEW

The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

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

 

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2040, the world’s population is projected to grow to approximately 9 billion people, or about 2 billion more than in 2010. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. As economies and populations grow, and as living standards improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 35 percent from 2010 to 2040. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organisation for Economic Co-operation and Development). 

As expanding prosperity drives global energy demand higher, increasing use of energy-efficient and lower-emission fuels, technologies and practices will continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2040, affecting energy requirements for transportation, power generation, industrial applications, and residential and commercial needs.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 40 percent from 2010 to 2040. The growth in transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period. Nearly all the world’s transportation fleets will continue to run on liquid fuels, which are abundant, widely available, easy to transport, and provide a large quantity of energy in small volumes.

Demand for electricity around the world is likely to increase approximately 85 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation is expected to remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and become the leading source of generated electricity by 2040, reflecting the efficiency of gas-fired power plants. Today, coal has the largest fuel share in the power sector, but its share is likely to decline significantly by 2040 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by hydropower and wind, are also expected to grow significantly over the period.

41 


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

 

 

Liquid fuels provide the largest share of global energy supplies today due to their broad-based availability, affordability and ease of transportation, distribution and storage to meet consumer needs. By 2040, global demand for liquid fuels is expected to grow to approximately 115 million barrels of oil‑equivalent per day, an increase of almost 30 percent from 2010. Globally, crude production from traditional conventional sources will likely decrease slightly through 2040, with significant development activity mostly offsetting natural declines from these fields. However, this decrease is expected to be more than offset by rising production from a variety of emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.

Natural gas is a versatile fuel, suitable for a wide variety of applications, and is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise about 65 percent from 2010 to 2040, with about half of that increase in the Asia Pacific region. Helping meet these needs will be significant growth in supplies of unconventional gas – the natural gas found in shale and other rock formations that was once considered uneconomic to produce. About two-thirds of the growth in natural gas supplies is expected to be from unconventional sources, which will account for close to 35 percent of global gas supplies by 2040. The worldwide liquefied natural gas (LNG) market is expected to more than triple by 2040, stimulated by growing natural gas demand.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the 2025-2030 timeframe. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, as many nations expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to reach about 15 percent of total energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 450 percent from 2010 to 2040, when they will be approaching 4 percent of world energy.

The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2014‑2040 will be about $28 trillion (measured in 2013 dollars) or more than $1 trillion per year on average.

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

The information provided in the Long-Term Business Outlook includes ExxonMobil’s internal estimates and forecasts based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.

 

Upstream

ExxonMobil continues to maintain a diverse portfolio of exploration and development opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include capturing material and accretive opportunities to continually high-grade the resource portfolio, exercising a disciplined approach to investing and cost management, developing and applying high-impact technologies, pursuing productivity and efficiency gains, growing profitable oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees, and investment in the communities within which we operate.

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

42 


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

 

 

nature and the extent of the risks disclosed in Item 1A. Risk Factors, or result in a material change in our level of unit operating expenses.

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

The markets for crude oil and natural gas have a history of significant price volatility. After some years of relatively stable prices, the end of 2014 saw crude prices drop to levels not seen since 2009. ExxonMobil believes prices over the long term will continue to be driven by market supply and demand, with the demand side largely being a function of global economic growth. To manage the risks associated with price, ExxonMobil evaluates annual plans and all investments across a wide range of price scenarios. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment, cost management, and asset enhancement programs.

 

Downstream

ExxonMobil’s Downstream is a large, diversified business with refining, logistics, and marketing complexes around the world. The Corporation has a presence in mature markets in North America and Europe, as well as in the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include targeting best‑in‑class operations in all aspects of the business, maximizing value from advanced technologies, capitalizing on integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, operating efficiently and effectively, and providing quality, valued products and services to customers.

ExxonMobil has an ownership interest in 30 refineries, located in 17 countries, with distillation capacity of 5.2 million barrels per day and lubricant basestock manufacturing capacity of 131 thousand barrels per day. ExxonMobil’s fuels and lubes marketing businesses have significant global reach, with multiple channels to market serving a diverse customer base. Our portfolio of world-renowned brands includes Exxon, Mobil, Esso  and Mobil 1.  

The downstream industry environment remains challenging. Demand weakness and overcapacity in the refining sector will continue to increase competitive pressure. In the near term, we see variability in refining margins, with some regions seeing weaker margins as new capacity additions outpace global demand. In North America, lower raw material and energy cost driven by increasing crude oil and natural gas production has strengthened refining margins over the past few years.  

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

ExxonMobil’s long‑term outlook is that industry refining margins will remain subject to intense competition as, in the near term, new capacity additions outpace the growth in global demand. Additionally, as described in more detail in Item 1A. Risk Factors, proposed carbon policy and other climate-related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining business. ExxonMobil’s integration across the value chain, from refining to marketing, enhances overall value in both fuels and lubricants businesses.

In the retail fuels marketing business, competition has caused inflation-adjusted margins to decline. In 2014, ExxonMobil expanded its branded retail site network in the U.S. and progressed the multi‑year transition of the direct served (i.e., dealer, company‑operated) retail network in portions of Europe to a more capital‑efficient branded distributor model. ExxonMobil is increasing investment in its fuels brands and developing multiple programs that will enhance the value of its consumer retail offer. The company’s lubricants business continues to grow, leveraging world-class brands and integration with industry‑leading basestock refining capability. ExxonMobil remains a market leader in the high‑value synthetic lubricants sector where competition is increasing.   

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

43 


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

 

 

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

 

Chemical

Worldwide petrochemical demand continued to improve in 2014, led by growing demand from Asia Pacific manufacturers of industrial and consumer products. North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low-cost feedstock and energy savings. Specialty product margins declined reflecting significant new industry capacity.

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

In 2014, ExxonMobil began construction of a major expansion at our Texas facilities, including a new world-scale ethane cracker and polyethylene lines, to capitalize on low-cost feedstock and energy supplies in North America and meet rapidly growing demand for premium polymers. Construction of new halobutyl rubber and hydrocarbon resin units also started in Singapore to further extend our specialty product capacity in Asia. At the joint venture facility in Al-Jubail, Saudi Arabia, construction continued on the specialty elastomers project that is expected to start-up in 2015.

 

REVIEW OF 2014 AND 2013 RESULTS

 

 

 

 

 

2014

 

2013

 

2012

 

 

(millions of dollars)

Earnings (U.S. GAAP)

 

 

 

 

 

 

Net income attributable to ExxonMobil (U.S. GAAP)

 

32,520

 

32,580

 

44,880

 

Upstream

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

United States

 

5,197

 

4,191

 

3,925

 

Non-U.S.

 

22,351

 

22,650

 

25,970

 

 

Total

 

27,548

 

26,841

 

29,895

 

2014

Upstream earnings were $27,548 million, up $707 million from 2013. Lower prices decreased earnings by $2.0 billion. Favorable volume effects increased earnings by $510 million. All other items, primarily asset sales and favorable U.S. deferred income tax items, increased earnings by $2.2 billion. On an oil‑equivalent basis, production of 4.0 million barrels per day was down 4.9 percent compared to 2013. Excluding the impact of the expiry of the Abu Dhabi onshore concession, production decreased 1.7 percent. Liquids production of 2.1 million barrels per day decreased 91,000 barrels per day compared to 2013. The Abu Dhabi onshore concession expiry reduced volumes by 135,000 barrels per day. Excluding this impact, liquids production was up 2 percent, driven by project ramp‑up and work programs. Natural gas production of 11.1 billion cubic feet per day decreased 691 million cubic feet per day from 2013, as expected U.S. field decline and lower European demand were partially offset by project ramp‑up and work programs. Earnings from U.S. Upstream operations were $5,197 million, up $1,006 million from 2013. Earnings outside the U.S. were $22,351 million, down $299 million from the prior year.

 

2013

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

44 


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

 

 

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

  

 

Upstream Additional Information

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

 

 

 

(thousands of barrels daily)

Volumes Reconciliation (Oil-equivalent production)(1) 

 

 

 

 

 

Prior year

 

 

 

4,175

 

4,239

 

Entitlements - Net Interest

 

 

 

(4)

 

(38)

 

Entitlements - Price / Spend / Other

 

 

 

(43)

 

(9)

 

Quotas

 

 

 

-

 

3

 

Divestments

 

 

 

(31)

 

(26)

 

United Arab Emirates Onshore Concession Expiry

 

 

 

(135)

 

-

 

Growth / Other

 

 

 

7

 

6

Current Year

 

 

 

3,969

 

4,175

 

 

 

 

 

 

 

 

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

 

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

 

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

 

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

 

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

 

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

 

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

45 


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

 

 

Downstream

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

Downstream

 

 

 

 

 

 

 

United States

 

1,618

 

2,199

 

3,575

 

Non-U.S.

 

1,427

 

1,250

 

9,615

 

 

Total

 

3,045

 

3,449

 

13,190

 

2014

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

 

2013

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

  

46 


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

 

 

Chemical

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

Chemical

 

 

 

 

 

 

 

United States

 

2,804

 

2,755

 

2,220

 

Non-U.S.

 

1,511

 

1,073

 

1,678

 

 

Total

 

4,315

 

3,828

 

3,898

 

2014

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

 

2013

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

  

 

Corporate and Financing

 

 

 

 

2014

 

2013

 

2012

 

 

(millions of dollars)

 

 

 

 

 

 

 

Corporate and financing

 

(2,388)

 

(1,538)

 

(2,103)

 

2014

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

 

2013

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

  

47 


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

 

 

LIQUIDITY AND CAPITAL RESOURCES

 

 

 

 

 

 

 

 

 

 

 

Sources and Uses of Cash

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

Net cash provided by/(used in)

 

 

 

 

 

 

 

Operating activities

 

45,116

 

44,914

 

56,170

 

Investing activities

 

(26,975)

 

(34,201)

 

(25,601)

 

Financing activities

 

(17,888)

 

(15,476)

 

(33,868)

Effect of exchange rate changes

 

(281)

 

(175)

 

217

Increase/(decrease) in cash and cash equivalents

 

(28)

 

(4,938)

 

(3,082)

 

 

 

 

 

 

 

 

 

 

 

(December 31)

Cash and cash equivalents

 

4,616

 

4,644

 

9,582

Cash and cash equivalents - restricted

 

42

 

269

 

341

Total cash and cash equivalents

 

4,658

 

4,913

 

9,923

 

Total cash and cash equivalents were $4.7 billion at the end of 2014, $0.3 billion lower than the prior year. The major sources of funds in 2014 were net income including noncontrolling interests of $33.6 billion, the adjustment for the noncash provision of $17.3 billion for depreciation and depletion, a net debt increase of $7.0 billion and collection of advances of $3.3 billion. The major uses of funds included spending for additions to property, plant and equipment of $33.0 billion, the purchase of shares of ExxonMobil stock of $13.2 billion, dividends to shareholders of $11.6 billion and a change in working capital, excluding cash and debt, of $4.9 billion. Included in total cash and cash equivalents at year-end 2014 was $42 million of restricted cash.

Total cash and cash equivalents were $4.9 billion at the end of 2013, $5.0 billion lower than the prior year. The major sources of funds in 2013 were net income including noncontrolling interests of $33.4 billion, the adjustment for the noncash provision of $17.2 billion for depreciation and depletion, and a net debt increase of $11.6 billion. The major uses of funds included spending for additions to property, plant and equipment of $33.7 billion, the purchase of ExxonMobil stock of $16.0 billion, dividends to shareholders of $10.9 billion and a change in working capital, excluding cash and debt, of $4.7 billion. Included in total cash and cash equivalents at year-end 2013 was $0.3 billion of restricted cash. For additional details, see the Consolidated Statement of Cash Flows.

The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. On December 31, 2014, the Corporation had unused committed short-term lines of credit of $6.3 billion and unused committed long-term lines of credit of $0.5 billion. Cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns.

To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at an average of approximately 3 percent per year over the next few years. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and the impact of fiscal and commercial terms.

The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunities and project execution. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, the impact of fiscal and commercial terms, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.

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

48 


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

 

 

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

 

Cash Flow from Operating Activities

 

2014

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

 

2013

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

 

Cash Flow from Investing Activities

 

2014

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

 

2013

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

 

Cash Flow from Financing Activities

 

2014

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

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

During 2014, Exxon Mobil Corporation purchased 136 million shares of its common stock for the treasury at a gross cost of $13.2 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 3.1 percent from 4,335 million to 4,201 million at the end of 2014. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

49 


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

 

 

2013

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

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

During 2013, Exxon Mobil Corporation purchased 177 million shares of its common stock for the treasury at a gross cost of $16.0 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 3.7 percent from 4,502 million to 4,335 million at the end of 2013. Purchases were made in both the open market and through negotiated transactions.

50 


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

 

 

Commitments

Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2014. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

 

 

 

Payments Due by Period

 

 

Note

 

 

 

 

 

2020

 

 

 

 

Reference

 

 

 

2016-

 

and

 

 

Commitments

Number

 

2015

 

2019

 

Beyond

 

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

Long-term debt  (1) 

14

 

-

 

6,755

 

4,898

 

11,653

 

 – Due in one year  (2) 

6

 

770

 

-

 

-

 

770

Asset retirement obligations  (3) 

9

 

1,055

 

2,763

 

9,606

 

13,424

Pension and other postretirement obligations  (4) 

17

 

1,524

 

4,346

 

20,664

 

26,534

Operating leases  (5) 

11

 

2,034

 

2,883

 

1,296

 

6,213

Unconditional purchase obligations  (6) 

16

 

150

 

608

 

337

 

1,095

Take-or-pay obligations  (7) 

 

 

2,973

 

10,671

 

14,065

 

27,709

Firm capital commitments  (8) 

 

 

16,065

 

7,893

 

1,643

 

25,601

 

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $9.0 billion as of December 31, 2014, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in Note 19, Income, Sales-Based and Other Taxes.

Notes:

(1)   Includes capitalized lease obligations of $375 million.

(2)   The amount due in one year is included in notes and loans payable of $17,468 million.

(3)   The fair value of asset retirement obligations, primarily upstream asset removal costs at the completion of field life.

(4)   The amount by which the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in 2015 and estimated benefit payments for unfunded plans in all years.

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

(6)   Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $1,095 million mainly pertain to pipeline throughput agreements and include $433 million of obligations to equity companies.

(7)   Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $27,709 million mainly pertain to pipeline, manufacturing supply and terminal agreements.

(8)   Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $25.6 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $13.9 billion was associated with projects in Africa, Canada, Australia, United Arab Emirates, Malaysia and Kazakhstan. The Corporation expects to fund the majority of these projects with internally generated funds, supplemented by long-term and short-term debt.

51 


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

 

 

Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2014, for guarantees relating to notes, loans and performance under contracts (Note 16). Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure. These guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

 

Financial Strength

On December 31, 2014, the Corporation’s unused short-term committed lines of credit totaled approximately $6.3 billion (Note 6) and unused long-term committed lines of credit totaled approximately $0.5 billion (Note 14). The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness.

 

 

 

2014

 

2013

 

2012

Fixed-charge coverage ratio (times)

 

46.9

 

55.7

 

62.4

Debt to capital (percent)

 

13.9

 

11.2

 

6.3

Net debt to capital (percent)

 

11.9

 

9.1

 

1.2

 

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

 

Litigation and Other Contingencies

As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 16 for additional information on legal proceedings and other contingencies.

52 


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

 

 

CAPITAL AND EXPLORATION EXPENDITURES

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

2013

 

 

U.S.

Non-U.S.

Total

 

U.S.

Non-U.S.

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Upstream (1) 

9,401

 

23,326

 

32,727

 

9,145

 

29,086

 

38,231

Downstream

1,310

 

1,724

 

3,034

 

951

 

1,462

 

2,413

Chemical

1,690

 

1,051

 

2,741

 

963

 

869

 

1,832

Other

35

 

-

 

35

 

13

 

-

 

13

 

Total

12,436

 

26,101

 

38,537

 

11,072

 

31,417

 

42,489

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Exploration expenses included.

 

 

 

 

 

 

 

 

 

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

Upstream spending of $32.7 billion in 2014 was down 14 percent from 2013, reflecting the absence of $4.2 billion of property acquisition costs in 2013. Investments in 2014 included projects in the U.S. Gulf of Mexico, U.S. onshore drilling, exploration in Russia and continued progress on world-class projects in Canada and Australia. The majority of expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2014, and has been over 60 percent for the last ten years, indicating that proved reserves are consistently moved from undeveloped to developed status.

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

 

TAXES

 

 

 

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Income taxes

 

18,015

 

24,263

 

31,045

 

Effective income tax rate

 

41%

 

48%

 

44%

Sales-based taxes

 

29,342

 

30,589

 

32,409

All other taxes and duties

 

35,515

 

36,396

 

38,857

 

 Total 

 

82,872

 

91,248

 

102,311

 

2014

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

 

2013

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

  

53 


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

 

 

ENVIRONMENTAL MATTERS

 

Environmental Expenditures

 

 

 

 

 

 

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

Capital expenditures

 

2,666

 

2,474

Other expenditures

 

3,522

 

3,538

 

Total

 

6,188

 

6,012

 

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels, as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions, and expenditures for asset retirement obligations. Using definitions and guidelines established by the American Petroleum Institute, ExxonMobil’s 2014 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $6.2 billion. The total cost for such activities is expected to remain in this range in 2015 and 2016 (with capital expenditures approximately 40 percent of the total).

 

Environmental Liabilities

The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2014 for environmental liabilities were $780 million ($321 million in 2013) and the balance sheet reflects accumulated liabilities of $1,066 million as of December 31, 2014, and $773 million as of December 31, 2013.

 

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1) 

 

2014

 

2013

 

2012

 

 

 

Crude oil and NGL ($/barrel)

 

87.42

 

97.48

 

100.29

Natural gas ($/kcf)

 

4.68

 

4.60

 

3.90

 

 

 

 

 

 

 

(1)  Consolidated subsidiaries.

 

 

 

 

 

 

 

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $350 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $175 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.

In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

 

54 


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

 

 

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.

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

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation evaluates the viability of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.

The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods of low commodity prices.

 

Risk Management

The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. With respect to derivatives activities, the Corporation believes that there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivatives described in Note 13. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.

The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt. Some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s limited use of the currency exchange contracts are not material.

 

Inflation and Other Uncertainties

The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to minimize costs in all commodity price environments through its economies of scale in global procurement and its efficient project management practices.

55 


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

 

 

RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the Financial Accounting Standards Board issued a new standard, Revenue from Contracts with Customers. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry specific requirements, and expands disclosure requirements. The standard is required to be adopted beginning January 1, 2017. ExxonMobil is evaluating the standard and its effect on the Corporation’s financial statements. 

 

CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.

 

Oil and Gas Reserves

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are an integral part of investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis to calculate unit-of-production depreciation rates and to evaluate impairment.

Oil and gas reserves include both proved and unproved reserves. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2.

Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2014 (including both consolidated and equity company reserves), and has been over 60 percent for the last ten years, indicating that proved reserves are consistently moved from undeveloped to developed status.

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

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved reserves or proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

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

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

56 


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

 

 

adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if its undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value.

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

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

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

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

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. Future prices used for any impairment tests will vary from the ones used in the supplemental oil and gas disclosure and could be lower or higher for any given year.

 

Asset Retirement Obligations

The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations are disclosed in Note 9 to the financial statements.

 

Suspended Exploratory Well Costs

The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10 to the financial statements.

 

Consolidations

The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing the Corporation’s interest in the underlying net assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.

Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks, and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an

57 


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

 

 

alternative accounting method that would require each investor to consolidate its share of all assets and liabilities in these partially-owned companies rather than only its interest in net equity. This method of accounting for investments in partially-owned companies is not permitted by U.S. GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by U.S. GAAP standards, the Corporation includes its share of debt of these partially-owned companies in the determination of average capital employed.

 

Pension Benefits

The Corporation and its affiliates sponsor about 100 defined benefit (pension) plans in over 40 countries. The Pension and Other Postretirement Benefits footnote (Note 17) provides details on pension obligations, fund assets and pension expense.

Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.

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

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

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2014 was 7.25 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 7 percent and 10 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $170 million before tax.

Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.

 

Litigation Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.

The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.

Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material

58 


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

 

 

adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

 

Tax Contingencies

The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.

The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 19.

 

Foreign Currency Translation

The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.

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

  

 

59 


MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

 

 

 

Management, including the Corporation’s Chief Executive Officer, Principal Financial Officer, and Principal Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2014.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014, as stated in their report included in the Financial Section of this report.

 

 

 

 

 

 

 

Rex W. Tillerson

Chief Executive Officer

Andrew P. Swiger

Senior Vice President

(Principal Financial Officer)

David S. Rosenthal

Vice President and Controller

(Principal Accounting Officer)

  

60 


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

 

To the Shareholders of Exxon Mobil Corporation:

In our opinion, the accompanying Consolidated Balance Sheets and the related Consolidated Statements of Income, Comprehensive Income, Changes in Equity and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 25, 2015

 

61 


CONSOLIDATED STATEMENT OF INCOME 

  

 

 

 

Note

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

Number

 

2014

 

2013

 

2012

 

 

 

 

 

(millions of dollars)

Revenues and other income

 

 

 

 

 

 

 

 

Sales and other operating revenue (1)

 

 

394,105

 

420,836

 

451,509

 

Income from equity affiliates

7

 

13,323

 

13,927

 

15,010

 

Other income

 

 

4,511

 

3,492

 

14,162

 

 

Total revenues and other income

 

 

411,939

 

438,255

 

480,681

Costs and other deductions

 

 

 

 

 

 

 

 

Crude oil and product purchases

 

 

225,972

 

244,156

 

263,535

 

Production and manufacturing expenses

 

 

40,859

 

40,525

 

38,521

 

Selling, general and administrative expenses

 

 

12,598

 

12,877

 

13,877

 

Depreciation and depletion

 

 

17,297

 

17,182

 

15,888

 

Exploration expenses, including dry holes

 

 

1,669

 

1,976

 

1,840

 

Interest expense

 

 

286

 

9

 

327

 

Sales-based taxes (1)

19

 

29,342

 

30,589

 

32,409

 

Other taxes and duties

19

 

32,286

 

33,230

 

35,558

 

 

Total costs and other deductions

 

 

360,309

 

380,544

 

401,955

Income before income taxes

 

 

51,630

 

57,711

 

78,726

 

Income taxes

19

 

18,015

 

24,263

 

31,045

Net income including noncontrolling interests

 

 

33,615

 

33,448

 

47,681

 

Net income attributable to noncontrolling interests

 

 

1,095

 

868

 

2,801

Net income attributable to ExxonMobil

 

 

32,520

 

32,580

 

44,880

 

 

 

 

 

 

 

 

 

 

Earnings per common share (dollars) 

12

 

7.60

 

7.37

 

9.70

 

 

 

 

 

 

 

 

 

 

Earnings per common share - assuming dilution (dollars) 

12

 

7.60

 

7.37

 

9.70

 

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

 

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

   

 

62 


CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

33,615

 

33,448

 

47,681

Other comprehensive income (net of income taxes)

 

 

 

 

 

 

 

Foreign exchange translation adjustment

 

(5,847)

 

(3,620)

 

920

 

Adjustment for foreign exchange translation (gain)/loss

 

 

 

 

 

 

 

 

included in net income

 

152

 

(23)

 

(4,352)

 

Postretirement benefits reserves adjustment (excluding amortization)

 

(4,262)

 

3,174

 

(3,574)

 

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs

 

1,111

 

1,820

 

2,395

 

Unrealized change in fair value of stock investments

 

(63)

 

 -  

 

 -  

 

Realized (gain)/loss from stock investments included in net income

 

3

 

 -  

 

 -  

 

 

Total other comprehensive income

 

(8,906)

 

1,351

 

(4,611)

Comprehensive income including noncontrolling interests

 

24,709

 

34,799

 

43,070

 

Comprehensive income attributable to noncontrolling interests

 

421

 

760

 

1,251

Comprehensive income attributable to ExxonMobil

 

24,288

 

34,039

 

41,819

 

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

  

 

63 


CONSOLIDATED BALANCE SHEET

  

 

 

 

 

Note

 

 

 

 

 

 

 

 

Reference

 

Dec. 31

 

Dec. 31

 

 

 

 

Number

 

2014

 

2013

 

 

 

 

 

 

(millions of dollars)

Assets

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

4,616

 

4,644

 

 

Cash and cash equivalents - restricted

 

 

42

 

269

 

 

Notes and accounts receivable, less estimated doubtful amounts

6

 

28,009

 

33,152

 

 

Inventories

 

 

 

 

 

 

 

 

Crude oil, products and merchandise

3

 

12,384

 

12,117

 

 

 

Materials and supplies

 

 

4,294

 

4,018

 

 

Other current assets

 

 

3,565

 

5,108

 

 

 

Total current assets

 

 

52,910

 

59,308

 

Investments, advances and long-term receivables

8

 

35,239

 

36,328

 

Property, plant and equipment, at cost, less accumulated depreciation

 

 

 

 

 

 

 

and depletion

9

 

252,668

 

243,650

 

Other assets, including intangibles, net

 

 

8,676

 

7,522

 

 

 

Total assets

 

 

349,493

 

346,808

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Notes and loans payable

6

 

17,468

 

15,808

 

 

Accounts payable and accrued liabilities

6

 

42,227

 

48,085

 

 

Income taxes payable

 

 

4,938

 

7,831

 

 

 

Total current liabilities

 

 

64,633

 

71,724

 

Long-term debt

14

 

11,653

 

6,891

 

Postretirement benefits reserves

17

 

25,802

 

20,646

 

Deferred income tax liabilities

19

 

39,230

 

40,530

 

Long-term obligations to equity companies

 

 

5,325

 

4,742

 

Other long-term obligations

 

 

21,786

 

21,780

 

 

 

Total liabilities

 

 

168,429

 

166,313

 

 

 

 

 

 

 

 

 

Commitments and contingencies

16

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

Common stock without par value

 

 

 

 

 

 

 

(9,000 million shares authorized, 8,019 million shares issued)

 

 

10,792

 

10,077

 

Earnings reinvested

 

 

408,384

 

387,432

 

Accumulated other comprehensive income

 

 

(18,957)

 

(10,725)

 

Common stock held in treasury

 

 

 

 

 

 

 

(3,818 million shares in 2014 and 3,684 million shares in 2013)

 

 

(225,820)

 

(212,781)

 

 

 

ExxonMobil share of equity

 

 

174,399

 

174,003

 

Noncontrolling interests

 

 

6,665

 

6,492

 

 

 

Total equity

 

 

181,064

 

180,495

 

 

 

Total liabilities and equity

 

 

349,493

 

346,808

 

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

   

 

64 


CONSOLIDATED STATEMENT OF CASH FLOWS 

  

 

 

 

 

 

Note

 

 

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

 

 

Number

 

2014

 

2013

 

2012

 

 

 

 

 

 

 

(millions of dollars)

Cash flows from operating activities

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

 

33,615

 

33,448

 

47,681

 

Adjustments for noncash transactions

 

 

 

 

 

 

 

 

 

Depreciation and depletion

 

 

17,297

 

17,182

 

15,888

 

 

Deferred income tax charges/(credits)

 

 

1,540

 

754

 

3,142

 

 

Postretirement benefits expense

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) net payments

 

 

524

 

2,291

 

(315)

 

 

Other long-term obligation provisions

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) payments

 

 

1,404

 

(2,566)

 

1,643

 

Dividends received greater than/(less than) equity in current

 

 

 

 

 

 

 

 

 

earnings of equity companies

 

 

(358)

 

3

 

(1,157)

 

Changes in operational working capital, excluding cash and debt

 

 

 

 

 

 

 

 

Reduction/(increase)

- Notes and accounts receivable

 

 

3,118

 

(305)

 

(1,082)

 

 

 

 

- Inventories

 

 

(1,343)

 

(1,812)

 

(1,873)

 

 

 

 

- Other current assets

 

 

(68)

 

(105)

 

(42)

 

 

Increase/(reduction)

- Accounts and other payables

 

 

(6,639)

 

(2,498)

 

3,624

 

Net (gain) on asset sales

5

 

(3,151)

 

(1,828)

 

(13,018)

 

All other items - net

 

 

(823)

 

350

 

1,679

 

 

Net cash provided by operating activities

 

 

45,116

 

44,914

 

56,170

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

 

(32,952)

 

(33,669)

 

(34,271)

 

Proceeds associated with sales of subsidiaries, property, plant

 

 

 

 

 

 

 

 

 

and equipment, and sales and returns of investments

5

 

4,035

 

2,707

 

7,655

 

Decrease/(increase) in restricted cash and cash equivalents

 

 

227

 

72

 

63

 

Additional investments and advances

 

 

(1,631)

 

(4,435)

 

(598)

 

Collection of advances

 

 

3,346

 

1,124

 

1,550

 

 

Net cash used in investing activities

 

 

(26,975)

 

(34,201)

 

(25,601)

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

Additions to long-term debt

 

 

5,731

 

345

 

995

 

Reductions in long-term debt

 

 

(69)

 

(13)

 

(147)

 

Additions to short-term debt

 

 

-

 

16

 

958

 

Reductions in short-term debt

 

 

(745)

 

(756)

 

(4,488)

 

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

 

2,049

 

12,012

 

(226)

 

Cash dividends to ExxonMobil shareholders

 

 

(11,568)

 

(10,875)

 

(10,092)

 

Cash dividends to noncontrolling interests

 

 

(248)

 

(304)

 

(327)

 

Changes in noncontrolling interests

 

 

-

 

(1)

 

204

 

Tax benefits related to stock-based awards

 

 

115

 

48

 

130

 

Common stock acquired

 

 

(13,183)

 

(15,998)

 

(21,068)

 

Common stock sold

 

 

30

 

50

 

193

 

 

Net cash used in financing activities

 

 

(17,888)

 

(15,476)

 

(33,868)

Effects of exchange rate changes on cash

 

 

(281)

 

(175)

 

217

Increase/(decrease) in cash and cash equivalents

 

 

(28)

 

(4,938)

 

(3,082)

Cash and cash equivalents at beginning of year

 

 

4,644

 

9,582

 

12,664

Cash and cash equivalents at end of year

 

 

4,616

 

4,644

 

9,582

 

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

   

 

65 


CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil Share of Equity

 

 

 

 

 

 

 

 

 

 

 

Accumulated

Common

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

Stock

ExxonMobil

Non-

 

 

 

 

 

 

Common

 

Earnings

Comprehensive

Held in

 

Share of

controlling

Total

 

 

 

 

Stock

Reinvested

Income

 

Treasury

 

Equity

 

Interests

 

Equity

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2011

 

9,512

 

330,939

 

(9,123)

 

(176,932)

 

154,396

 

6,348

 

160,744

 

Amortization of stock-based awards

 

806

 

 -  

 

 -  

 

 -  

 

806

 

 -  

 

806

 

Tax benefits related to stock-based awards

 

178

 

 -  

 

 -  

 

 -  

 

178

 

 -  

 

178

 

Other

 

(843)

 

 -  

 

 -  

 

 -  

 

(843)

 

(1,441)

 

(2,284)

 

Net income for the year

 

 -  

 

44,880

 

 -  

 

 -  

 

44,880

 

2,801

 

47,681

 

Dividends - common shares

 

 -  

 

(10,092)

 

 -  

 

 -  

 

(10,092)

 

(327)

 

(10,419)

 

Other comprehensive income

 

 -  

 

 -  

 

(3,061)

 

 -  

 

(3,061)

 

(1,550)

 

(4,611)

 

Acquisitions, at cost

 

 -  

 

 -  

 

 -  

 

(21,068)

 

(21,068)

 

(34)

 

(21,102)

 

Dispositions

 

 -  

 

 -  

 

 -  

 

667

 

667

 

 -  

 

667

Balance as of December 31, 2012

 

9,653

 

365,727

 

(12,184)

 

(197,333)

 

165,863

 

5,797

 

171,660

 

Amortization of stock-based awards

 

761

 

 -  

 

 -  

 

 -  

 

761

 

 -  

 

761

 

Tax benefits related to stock-based awards

 

162

 

 -  

 

 -  

 

 -  

 

162

 

 -  

 

162

 

Other

 

(499)

 

 -  

 

 -  

 

 -  

 

(499)

 

240

 

(259)

 

Net income for the year

 

 -  

 

32,580

 

 -  

 

 -  

 

32,580

 

868

 

33,448

 

Dividends - common shares

 

 -  

 

(10,875)

 

 -  

 

 -  

 

(10,875)

 

(304)

 

(11,179)

 

Other comprehensive income

 

 -  

 

 -  

 

1,459

 

 -  

 

1,459

 

(108)

 

1,351

 

Acquisitions, at cost

 

 -  

 

 -  

 

 -  

 

(15,998)

 

(15,998)

 

(1)

 

(15,999)

 

Dispositions

 

 -  

 

 -  

 

 -  

 

550

 

550

 

 -  

 

550

Balance as of December 31, 2013

 

10,077

 

387,432

 

(10,725)

 

(212,781)

 

174,003

 

6,492

 

180,495

 

Amortization of stock-based awards

 

780

 

 -  

 

 -  

 

 -  

 

780

 

 -  

 

780

 

Tax benefits related to stock-based awards

 

49

 

 -  

 

 -  

 

 -  

 

49

 

 -  

 

49

 

Other

 

(114)

 

 -  

 

 -  

 

 -  

 

(114)

 

 -  

 

(114)

 

Net income for the year

 

 -  

 

32,520

 

 -  

 

 -  

 

32,520

 

1,095

 

33,615

 

Dividends - common shares

 

 -  

 

(11,568)

 

 -  

 

 -  

 

(11,568)

 

(248)

 

(11,816)

 

Other comprehensive income

 

 -  

 

 -  

 

(8,232)

 

 -  

 

(8,232)

 

(674)

 

(8,906)

 

Acquisitions, at cost

 

 -  

 

 -  

 

 -  

 

(13,183)

 

(13,183)

 

 -  

 

(13,183)

 

Dispositions

 

 -  

 

 -  

 

 -  

 

144

 

144

 

 -  

 

144

Balance as of December 31, 2014

 

10,792

 

408,384

 

(18,957)

 

(225,820)

 

174,399

 

6,665

 

181,064

 

 

 

 

 

 

Held in

 

 

Common Stock Share Activity

 

Issued

 

Treasury

Outstanding

 

 

 

(millions of shares)

 

 

 

 

 

 

 

 

Balance as of December 31, 2011

 

8,019

 

(3,285)

 

4,734

 

Acquisitions

 

 -  

 

(244)

 

(244)

 

Dispositions

 

 -  

 

12

 

12

Balance as of December 31, 2012

 

8,019

 

(3,517)

 

4,502

 

Acquisitions

 

 -  

 

(177)

 

(177)

 

Dispositions

 

 -  

 

10

 

10

Balance as of December 31, 2013

 

8,019

 

(3,684)

 

4,335

 

Acquisitions

 

 -  

 

(136)

 

(136)

 

Dispositions

 

 -  

 

2

 

2

Balance as of December 31, 2014

 

8,019

 

(3,818)

 

4,201

 

 

 

 

 

 

 

 

 

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

   

 

66 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

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

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2014 presentation basis.

 

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses.

Amounts representing the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables.” The Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.”

Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in Accumulated Other Comprehensive Income.

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

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

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

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.

Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs).

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged item.

Fair Value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy

67 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

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

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

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

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

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

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

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

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

Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the Corporation.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

68 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.

Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates.

Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.

For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.

Stock-Based Payments. The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the price of the stock at the date of grant and is recognized in income over the requisite service period.

 

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2014 that had a material impact on the Corporation’s financial statements.

In May 2014, the Financial Accounting Standards Board issued a new standard, Revenue from Contracts with Customers. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry specific requirements, and expands disclosure requirements. The standard is required to be adopted beginning January 1, 2017. ExxonMobil is evaluating the standard and its effect on the Corporation’s financial statements. 

 

3. Miscellaneous Financial Information

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

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

In 2014, 2013 and 2012, net income included gains of $187 million, $282 million and $328 million, respectively, attributable to the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $10.6 billion and $21.2 billion at December 31, 2014, and 2013, respectively.

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

 

 

 

 

2014

 

2013

 

 

 

    (billions of dollars)

 

 

 

 

 

 

Petroleum products

 

4.1

 

3.9

Crude oil

 

4.6

 

4.7

Chemical products

 

2.9

 

2.9

Gas/other

 

0.8

 

0.6

 

Total

 

12.4

 

12.1

69 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4.     Other Comprehensive Income Information

 

 

 

Cumulative

 

Post-

 

 

 

 

 

 

 

 

Foreign

 

retirement

 

Unrealized

 

 

 

 

 

 

Exchange

 

Benefits

 

Change in

 

 

 

ExxonMobil Share of Accumulated Other

Translation

 

Reserves

 

Stock

 

 

 

Comprehensive Income

Adjustment

 

Adjustment

 

Investments

 

Total

 

 

 

(millions of dollars)

Balance as of December 31, 2011

4,168

 

 

(13,291)

 

 

 -  

 

 

(9,123)

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

842

 

 

(3,402)

 

 

 -  

 

 

(2,560)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

(2,600)

 

 

2,099

 

 

 -  

 

 

(501)

 

Total change in accumulated other comprehensive income

(1,758)

 

 

(1,303)

 

 

 -  

 

 

(3,061)

 

Balance as of December 31, 2012

2,410

 

 

(14,594)

 

 

 -  

 

 

(12,184)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2012

2,410

 

 

(14,594)

 

 

 -  

 

 

(12,184)

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(3,233)

 

 

2,963

 

 

 -  

 

 

(270)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

(23)

 

 

1,752

 

 

 -  

 

 

1,729

 

Total change in accumulated other comprehensive income

(3,256)

 

 

4,715

 

 

 -  

 

 

1,459

 

Balance as of December 31, 2013

(846)

 

 

(9,879)

 

 

 -  

 

 

(10,725)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2013

(846)

 

 

(9,879)

 

 

 -  

 

 

(10,725)

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(5,258)

 

 

(4,132)

 

 

(63)

 

 

(9,453)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

152

 

 

1,066

 

 

3

 

 

1,221

 

Total change in accumulated other comprehensive income

(5,106)

 

 

(3,066)

 

 

(60)

 

 

(8,232)

 

Balance as of December 31, 2014

(5,952)

 

 

(12,945)

 

 

(60)

 

 

(18,957)

 

 

Amounts Reclassified Out of Accumulated Other

 

 

 

 

 

 

Comprehensive Income - Before-tax Income/(Expense)

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

Foreign exchange translation gain/(loss) included in net income

 

 

 

 

 

 

 

(Statement of Income line: Other income)

 

(152)

 

23

 

4,352

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs (1) 

 

(1,571)

 

(2,616)

 

(3,621)

Realized change in fair value of stock investments included in net income

 

 

 

 

 

 

 

(Statement of Income line: Other income)

 

(5)

 

 -  

 

 -  

                 

 

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

 

Income Tax (Expense)/Credit For

 

 

 

 

 

Components of Other Comprehensive Income

2014

 

2013

 

2012

 

 

 

(millions of dollars)

Foreign exchange translation adjustment

292

 

218

 

(236)

Postretirement benefits reserves adjustment (excluding amortization)

2,009

 

(1,540)

 

1,619

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

adjustment included in net periodic benefit costs

(460)

 

(796)

 

(1,226)

Unrealized change in fair value of stock investments

34

 

 -  

 

 -  

Realized change in fair value of stock investments included in net income

(2)

 

 -  

 

 -  

Total

1,873

 

(2,118)

 

157

               

70 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

5. Cash Flow Information

The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

For 2014, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows includes before-tax gains from the sale of Hong Kong power operations, additional proceeds related to the 2013 sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale or exchange of Upstream properties in the U.S., Canada, and Malaysia. For 2013, the amount includes before-tax gains from the sale of a partial interest in Iraq, the sale of Downstream affiliates in the Caribbean and the sale of service stations. For 2012, the amount includes before-tax gains related to the Japan restructuring, the sale of an Upstream property in Angola, exchanges of Upstream properties, the sale of U.S. service stations and the sale of Downstream affiliates in Malaysia and Switzerland. These gains are reported in “Other income” on the Consolidated Statement of Income.

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

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

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

 

 

 

2014

 

2013

 

2012

 

 

(millions of dollars)

 

 

 

 

 

 

 

Cash payments for interest

 

380

 

426

 

555

 

 

 

 

 

 

 

Cash payments for income taxes

 

18,085

 

25,066

 

24,349



6. Additional Working Capital Information

 

 

 

 

Dec. 31

 

Dec. 31

 

 

 

 

2014

 

2013

 

 

 

 

(millions of dollars)

Notes and accounts receivable

 

 

 

 

 

Trade, less reserves of $113 million and $112 million

 

18,541

 

25,993

 

Other, less reserves of $48 million and $28 million

 

9,468

 

7,159

 

 

Total

 

28,009

 

33,152

 

 

 

 

 

 

 

Notes and loans payable

 

 

 

 

 

Bank loans

 

473

 

723

 

Commercial paper

 

16,225

 

14,051

 

Long-term debt due within one year

 

770

 

1,034

 

 

Total

 

17,468

 

15,808

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

 

 

 

 

Trade payables

 

25,286

 

30,920

 

Payables to equity companies

 

6,589

 

6,587

 

Accrued taxes other than income taxes

 

3,290

 

3,883

 

Other

 

7,062

 

6,695

 

 

Total

 

42,227

 

48,085

 

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

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

71 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7. Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in oil and gas exploration and production, natural gas marketing, and refining operations in North America; natural gas exploration, production and distribution, and downstream operations in Europe; and exploration, production, liquefied natural gas (LNG) operations, refining operations, petrochemical manufacturing, and fuel sales in Asia. Also included are several refining, petrochemical manufacturing, and marketing ventures.

The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. Differences between the company’s carrying value of an equity investment and its underlying equity in the net assets of the affiliate are assigned to the extent practicable to specific assets and liabilities based on the company’s analysis of the factors giving rise to the difference. The amortization of this difference, as appropriate, is included in “income from equity affiliates.”

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 14 percent, 13 percent and 16 percent in the years 2014, 2013 and 2012, respectively.

In 2013 and 2014, the Corporation and Rosneft established various entities to conduct exploration and research activities. Periods of disproportionate funding will result in the Corporation recognizing, during the early phases of the projects, an investment that is larger than its equity share in these entities. These joint ventures are considered Variable Interest Entities. However, since the Corporation is not the primary beneficiary of these entities, the joint ventures are reported as equity companies. In 2014, the European Union and United States imposed sanctions relating to the Russian energy sector. In compliance with the sanctions and all general and specific licenses, prohibited activities involving offshore Russia in the Black Sea, Arctic regions, and onshore western Siberia have been wound down. The Corporation's maximum exposure to loss from these joint ventures as of December 31, 2014, is $1.0 billion.

 

 

 

 

2014

 

2013

 

2012

Equity Company

 

 

ExxonMobil

 

ExxonMobil

 

      ExxonMobil

Financial Summary

 

Total

 

Share

 

Total

 

Share

 

Total

 

Share

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

183,708

 

55,855

 

236,161

 

68,084

 

224,953

 

67,572

Income before income taxes

 

65,549

 

19,014

 

69,454

 

19,999

 

69,411

 

20,882

Income taxes

 

20,520

 

5,684

 

21,618

 

6,069

 

20,703

 

5,868

 

Income from equity affiliates

 

45,029

 

13,330

 

47,836

 

13,930

 

48,708

 

15,014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

49,905

 

16,802

 

62,398

 

19,545

 

59,612

 

18,483

Long-term assets

 

110,754

 

33,619

 

116,450

 

35,695

 

111,131

 

33,798

 

Total assets

 

160,659

 

50,421

 

178,848

 

55,240

 

170,743

 

52,281

Current liabilities

 

37,333

 

11,472

 

54,550

 

15,243

 

49,698

 

14,265

Long-term liabilities

 

66,231

 

19,470

 

68,857

 

20,873

 

68,855

 

19,715

 

Net assets

 

57,095

 

19,479

 

55,441

 

19,124

 

52,190

 

18,301

 

 

 

 

 

 

 

 

 

 

 

 

 

 

72 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

A list of significant equity companies as of December 31, 2014, together with the Corporation’s percentage ownership interest, is detailed below:

 

 

Percentage

 

 

 

 

 

Ownership

 

 

 

 

 

Interest

 

 

 

 

Upstream

 

 

 

 

 

Aera Energy LLC

48

 

 

 

 

BEB Erdgas und Erdoel GmbH & Co. KG

50

 

 

 

 

Cameroon Oil Transportation Company S.A.

41

 

 

 

 

Cross Timbers Energy, LLC

50

 

 

 

 

Golden Pass LNG Terminal LLC

18

 

 

 

 

Karmorneftegaz Holding SARL

33

 

 

 

 

Marine Well Containment Company LLC

10

 

 

 

 

Nederlandse Aardolie Maatschappij B.V.

50

 

 

 

 

Qatar Liquefied Gas Company Limited

10

 

 

 

 

Qatar Liquefied Gas Company Limited (2)

24

 

 

 

 

Ras Laffan Liquefied Natural Gas Company Limited

25

 

 

 

 

Ras Laffan Liquefied Natural Gas Company Limited (II)

31

 

 

 

 

Ras Laffan Liquefied Natural Gas Company Limited (3)

30

 

 

 

 

South Hook LNG Terminal Company Limited

24

 

 

 

 

Tengizchevroil, LLP

25

 

 

 

 

Terminale GNL Adriatico S.r.l.

71

 

 

 

 

 

 

 

 

 

 

Downstream

 

 

 

 

 

Chalmette Refining, LLC

50

 

 

 

 

Fujian Refining & Petrochemical Co. Ltd.

25

 

 

 

 

Saudi Aramco Mobil Refinery Company Ltd.

50

 

 

 

 

 

 

 

 

 

 

Chemical

 

 

 

 

 

Al-Jubail Petrochemical Company

50

 

 

 

 

Infineum Holdings B.V.

50

 

 

 

 

Infineum USA L.P.

50

 

 

 

 

Saudi Yanbu Petrochemical Co.

50

 

 

 



8. Investments, Advances and Long-Term Receivables

 

 

 

 

Dec. 31,

 

Dec. 31,

 

 

 

 

2014

 

2013

 

 

 

 

(millions of dollars)

Companies carried at equity in underlying assets

 

 

 

 

 

Investments

 

20,017

 

19,619

 

Advances

 

9,818

 

10,476

 

 

Total equity company investments and advances

 

29,835

 

30,095

Companies carried at cost or less and stock investments carried at fair value

 

526

 

115

Long-term receivables and miscellaneous investments at cost or less, net of reserves

 

 

 

 

 

of $2,662 million and $2,938 million

 

4,878

 

6,118

 

 

Total

 

35,239

 

36,328

73 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

9. Property, Plant and Equipment and Asset Retirement Obligations

 

 

 

 

December 31, 2014

 

December 31, 2013

Property, Plant and Equipment

 

Cost

 

Net

 

Cost

 

Net

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Upstream

 

347,170

 

205,308

 

336,359

 

197,554

Downstream

 

53,327

 

22,639

 

54,456

 

23,219

Chemical

 

30,717

 

14,918

 

29,487

 

13,965

Other

 

15,575

 

9,803

 

14,215

 

8,912

 

Total

 

446,789

 

252,668

 

434,517

 

243,650

 

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

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

 

Asset Retirement Obligations

The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value.

Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.

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

 

 

 

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

Beginning balance

 

12,988

 

11,973

 

Accretion expense and other provisions

 

871

 

785

 

Reduction due to property sales

 

(151)

 

(97)

 

Payments made

 

(724)

 

(664)

 

Liabilities incurred

 

122

 

603

 

Foreign currency translation

 

(908)

 

(344)

 

Revisions

 

1,226

 

732

Ending balance

 

13,424

 

12,988

74 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

10. Accounting for Suspended Exploratory Well Costs

The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.

Change in capitalized suspended exploratory well costs:

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Balance beginning at January 1

 

2,707

 

2,679

 

2,881

 

Additions pending the determination of proved reserves

 

1,095

 

293

 

868

 

Charged to expense

 

(28)

 

(52)

 

(95)

 

Reclassifications to wells, facilities and equipment based on the

 

 

 

 

 

 

 

 

determination of proved reserves

 

(160)

 

(107)

 

(631)

 

Divestments/Other

 

(27)

 

(106)

 

(344)

Ending balance at December 31

 

3,587

 

2,707

 

2,679

Ending balance attributed to equity companies included above

 

645

 

13

 

3



Period end capitalized suspended exploratory well costs:

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Capitalized for a period of one year or less

 

1,095

 

293

 

866

 

Capitalized for a period of between one and five years

 

1,659

 

1,705

 

1,176

 

Capitalized for a period of between five and ten years

 

544

 

470

 

401

 

Capitalized for a period of greater than ten years

 

289

 

239

 

236

Capitalized for a period greater than one year - subtotal

 

2,492

 

2,414

 

1,813

 

 

Total

 

3,587

 

2,707

 

2,679

 

 

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.

 

 

 

 

2014

 

2013

 

2012

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

8

 

8

 

10

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

 

 

 

 

 

 

of greater than 12 months

 

53

 

50

 

45

 

 

Total

 

61

 

58

 

55

75 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

 

Years

 

 

 

Dec. 31,

Wells

 

Country/Project

2014

Drilled

Comment

 

(millions of dollars)

 

  Angola

 

 

 

 

 

   - Kaombo Split Hub Phase 2

 

20

 

2005 - 2006

  Evaluating development plan to tie into planned production facilities.

   - Perpetua-Zinia-Acacia

 

15

 

2008 - 2009

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

  Australia

 

 

 

 

 

   - East Pilchard

 

8

 

2001

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

 

 

 

 

 

  infrastructure.

   - SE Longtom

 

12

 

2010

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

   - SE Remora

 

38

 

2010

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

  Indonesia

 

 

 

 

 

   - Alas Tua West

 

16

 

2010

  Evaluating development plan to tie into planned production facilities.

   - Cepu Gas

 

28

 

2008 - 2011

  Development activity under way, while continuing commercial discussions with the

 

 

 

 

 

  government.

   - Kedung Keris

 

11

 

2011

  Evaluating development plan to tie into planned production facilities.

   - Natuna

 

118

 

1981 - 1983

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  on contract terms pursuant to executed Heads of Agreement.

  Kazakhstan

 

 

 

 

 

   - Kairan

 

53

 

2004 - 2007

  Evaluating commercialization and field development alternatives, while continuing

 

 

 

 

 

  discussions with the government regarding the development plan.

  Malaysia

 

 

 

 

 

   - Besar

 

18

 

1992 - 2010

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

   - Bindu

 

2

 

1995

  Awaiting capacity in existing/planned infrastructure.

  Nigeria

 

 

 

 

 

   - Bolia

 

15

 

2002 - 2006

  Evaluating development plan, while continuing discussions with the government

 

 

 

 

 

  regarding regional hub strategy.

   - Bosi

 

79

 

2002 - 2006

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  regarding development plan.

   - Bosi Central

 

16

 

2006

  Development activity under way, while continuing discussions with the government

 

 

 

 

 

  regarding development plan.

   - Erha Northeast

 

26

 

2008

  Evaluating development plan for tieback to existing production facilities.

   - Owowo

 

50

 

2009 - 2012

  Continuing discussions with the government regarding contract terms.

   - Pegi

 

32

 

2009

  Awaiting capacity in existing/planned infrastructure.

   - Satellite Field

 

12

 

2013

  Evaluating development plan to tie into planned production facilities.

      Development Phase 2

 

 

 

 

 

   - Other (4 projects)

 

14

 

2002

  Evaluating and pursuing development of several additional discoveries.

  Norway

 

 

 

 

 

   - Gamma

 

15

 

2008 - 2009

  Evaluating development plan for tieback to existing production facilities.

   - Lavrans

 

18

 

1995 - 1999

  Evaluating development plan, awaiting capacity in existing Kristin production facility.

   - Other (7 projects)

 

29

 

2008 - 2013

  Evaluating development plans, including potential for tieback to existing production

 

 

 

 

 

  facilities.

  Papua New Guinea

 

 

 

 

 

   - Juha

 

28

 

2007

  Progressing development plans to tie into existing LNG facilities.

   - P'nyang

 

58

 

2012

  Evaluating development alternatives to tie into existing/planned infrastructure.

  Republic of Congo

 

 

 

 

 

   - Mer Tres Profonde Sud

 

56

 

2000 - 2007

  Evaluating development alternatives, while continuing discussions with the government

 

 

 

 

 

  regarding development plan.

  United Kingdom

 

 

 

 

 

   - Phyllis

 

8

 

2004

  Evaluating development plan for tieback to existing production facilities.

  United States

 

 

 

 

 

   - Hadrian North

 

209

 

2010 - 2013

  Evaluating development plan to tie into existing production facilities.

   - Tip Top

 

31

 

2009

  Evaluating development concept and requisite facility upgrades.

  Total 2014 (38 projects)

 

1,035

 

 

 

76 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

11. Leased Facilities

At December 31, 2014, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $6,213 million as indicated in the table. Estimated related rental income from noncancelable subleases is $70 million.

 

 

 

 

 

 

 

 

Related

 

 

 

 

 

Lease Payments

 

Sublease

 

 

 

 

 

Under Minimum

 

Rental

 

 

 

 

 

Commitments

 

Income

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

2,034

 

 

31

 

 

 

2016

 

 

1,379

 

 

7

 

 

 

2017

 

 

774

 

 

6

 

 

 

2018

 

 

418

 

 

3

 

 

 

2019

 

 

312

 

 

3

 

 

 

2020 and beyond

 

 

1,296

 

 

20

 

 

 

     Total

 

 

6,213

 

 

70

 

 

 

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

 

 

 

2014

 

2013

 

2012

 

 

(millions of dollars)

 

 

 

 

 

 

 

Rental cost

 

4,077

 

3,841

 

3,851

Less sublease rental income

 

52

 

44

 

44

Net rental cost

 

4,025

 

3,797

 

3,807



12. Earnings Per Share

 

 

 

2014

 

2013

 

2012

Earnings per common share

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to ExxonMobil (millions of dollars)

 

32,520

 

32,580

 

44,880

 

 

 

 

 

 

 

Weighted average number of common shares outstanding (millions of shares)

 

4,282

 

4,419

 

4,628

 

 

 

 

 

 

 

Earnings per common share (dollars) (1)

 

7.60

 

7.37

 

9.70

 

 

 

 

 

 

 

Dividends paid per common share (dollars)

 

2.70

 

2.46

 

2.18

 

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

77 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

13. Financial Instruments and Derivatives

Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, excluding capitalized lease obligations, was $11.7 billion and $6.8 billion at December 31, 2014, and 2013, respectively, as compared to recorded book values of $11.3 billion and $6.5 billion at December 31, 2014, and 2013, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $5,500 million of long-term debt in the first quarter of 2014.

The fair value of long-term debt by hierarchy level at December 31, 2014, is: Level 1 $11,036 million; Level 2 $561 million; and Level 3 $63 million. 

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

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net asset of $75 million at year-end 2014 and a net asset of $1 million at year-end 2013. Assets and liabilities associated with derivatives are usually recorded either in “Other current assets” or “Accounts payable and accrued liabilities.”

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

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $110 million, $(7) million and $(23) million during 2014, 2013 and 2012, respectively. Income statement effects associated with derivatives are usually recorded either in “Sales and other operating revenue” or “Crude oil and product purchases.” 

The Corporation believes there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivative activities described above.

78 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

14. Long-Term Debt

At December 31, 2014, long-term debt consisted of $11,341 million due in U.S. dollars and $312 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $770 million, which matures within one year and is included in current liabilities. The increase in the book value of long-term debt reflects the Corporation’s issuance of $5,500 million of long-term debt in the first quarter of 2014. The amounts of long-term debt maturing in each of the four years after December 31, 2015, in millions of dollars, are: 2016 – $537; 2017 – $2,993; 2018 – $872; and 2019 – $2,353. At December 31, 2014, the Corporation’s unused long-term credit lines were $0.5 billion.

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

 

 

 

 

 

2014

 

2013

 

 

 

 

 

 

        (millions of dollars)

 

 

Exxon Mobil Corporation

 

 

 

 

 

 

 

0.921% notes due 2017

 

1,500

 

 -  

 

 

 

Floating-rate notes due 2017 (1)

 

750

 

 -  

 

 

 

1.819% notes due 2019

 

1,750

 

 -  

 

 

 

Floating-rate notes due 2019 (2) 

 

500

 

 -  

 

 

 

3.176% notes due 2024

 

1,000

 

 -  

 

 

 

 

  

 

 

 

 

 

 

XTO Energy Inc. (3) 

 

 

 

 

 

 

 

5.000% senior notes due 2015

 

 -  

 

132

 

 

 

5.300% senior notes due 2015

 

 -  

 

243

 

 

 

5.650% senior notes due 2016

 

207

 

212

 

 

 

6.250% senior notes due 2017

 

477

 

489

 

 

 

5.500% senior notes due 2018

 

383

 

389

 

 

 

6.500% senior notes due 2018

 

474

 

485

 

 

 

6.100% senior notes due 2036

 

199

 

200

 

 

 

6.750% senior notes due 2037

 

309

 

312

 

 

 

6.375% senior notes due 2038

 

236

 

238

 

 

 

 

 

 

 

 

 

 

 

Mobil Producing Nigeria Unlimited (4) 

 

 

 

 

 

 

 

Variable notes due 2015-2019

 

399

 

742

 

 

 

 

 

 

 

 

 

 

 

Esso (Thailand) Public Company Ltd. (5) 

 

 

 

 

 

 

 

Variable notes due 2015-2019

 

121

 

177

 

 

 

 

 

 

 

 

 

 

 

Mobil Corporation

 

 

 

 

 

 

 

8.625% debentures due 2021

 

249

 

249

 

 

 

 

 

 

 

 

 

 

 

Industrial revenue bonds due 2015-2051 (6) 

 

2,611

 

2,527

 

 

Other U.S. dollar obligations (7) 

 

104

 

112

 

 

Other foreign currency obligations

 

9

 

9

 

 

Capitalized lease obligations (8) 

 

375

 

375

 

 

 

 

Total long-term debt

 

11,653

 

6,891

 

 

 

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

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

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

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

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

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

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

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

79 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

15. Incentive Program

The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2014, remaining shares available for award under the 2003 Incentive Program were 108 million.  

Restricted Stock and Restricted Stock Units. Awards totaling 9,775 thousand, 9,729 thousand, and 10,017 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2014, 2013 and 2012, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. Shares for these awards are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares and units may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares and units in each award vesting after three years and the remaining 50 percent vesting after seven years. Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.

The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.

The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2014.

 

2014

 

 

 

 

Weighted Average

 

 

 

 

Grant-Date

Restricted stock and units outstanding

Shares

 

 

Fair Value per Share

 

(thousands)

 

 

(dollars)

 

 

 

 

 

 

 

Issued and outstanding at January 1

45,207

 

 

 

78.29

 

2013 award issued in 2014

9,705

 

 

 

94.47

 

Vested

(10,286)

 

 

 

79.89

 

Forfeited

(187)

 

 

 

78.89

 

Issued and outstanding at December 31

44,439

 

 

 

81.45

 

 

 

 

 

 

 

 

Value of restricted stock and units

 

2014

 

2013

 

2012

Grant price (dollars)

 

95.20

 

94.47

 

87.24

 

 

 

 

 

 

 

Value at date of grant:

 

(millions of dollars)

Restricted stock and units settled in stock

 

858

 

843

 

797

Units settled in cash

 

73

 

76

 

77

Total value

 

931

 

919

 

874

 

As of December 31, 2014, there was $2,339 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted stock units was $831 million, $854 million and $854 million for 2014, 2013 and 2012, respectively. The income tax benefit recognized in income related to this compensation expense was $76 million, $78 million and $79 million for the same periods, respectively. The fair value of shares and units vested in 2014, 2013 and 2012 was $946 million, $1,040 million and $926 million, respectively. Cash payments of $73 million, $67 million and $66 million for vested restricted stock units settled in cash were made in 2014, 2013 and 2012, respectively.

80 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

16. Litigation and Other Contingencies

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

Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2014, for guarantees relating to notes, loans and performance under contracts. Where guarantees for environmental remediation and other similar matters do not include a stated cap, the amounts reflect management’s estimate of the maximum potential exposure.

 

 

 

 

 

 

 

 

Dec. 31, 2014

 

 

 

 

 

 

Equity Company

Other Third-Party

 

 

 

 

 

Obligations (1) 

Obligations

 

Total

 

 

 

 

 

 

(millions of dollars)

 

 

Guarantees

 

 

 

 

 

 

 

 

 

Debt-related

 

3,506

 

 

41

 

 

3,547

 

Other

 

2,920

 

 

3,982

 

 

6,902

 

 

Total

 

6,426

 

 

4,023

 

 

10,449

 

 

 

 

 

 

 

 

 

 

 

(1) ExxonMobil share.

 

 

 

 

 

 

 

 

 

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

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

 

 

 

Payments Due by Period

 

 

 

 

2016-

2020 and

 

 

 

2015

 

2019

Beyond

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Unconditional purchase obligations (1) 

 

150

 

608

 

337

 

1,095

 

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

81 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. On October 9, 2014, the ICSID Tribunal issued its final award finding in favor of the ExxonMobil affiliates and awarding $1.6 billion as of the date of expropriation, June 27, 2007, and interest from that date at 3.25% compounded annually until the date of payment in full. The Tribunal also noted that one of the Cerro Negro Project agreements provides a mechanism to prevent double recovery between the ICSID award and all or part of an earlier award of $908 million to an ExxonMobil affiliate, Mobil Cerro Negro, Ltd., against PdVSA and a PdVSA affiliate, PdVSA CN, in an arbitration under the rules of the International Chamber of Commerce (ICC).  Following the favorable ICSID decision in the fourth quarter of 2014, ExxonMobil recognized earnings of $269 million, net of the remaining asset value, for the proceeds received from the earlier ICC award.           

Judgment was entered on the ICSID award by the United States District Court for the Southern District of New York on October 10, 2014. A motion to vacate that judgment on procedural grounds was filed by the Republic of Venezuela on October 14, 2014, which was denied by the court. Thereafter, the Republic of Venezuela filed a motion to modify the judgment by reducing the rate of interest to be paid on the ICSID award from the entry of the court’s judgment, until the date of payment.

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

The federal court in New York has stayed its judgment until such time as the stays of the ICSID award entered following the Government of Venezuela’s filing of its two applications have been lifted. The net impact of these matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.

An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil's affiliate is the operator of the block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC's lifting of crude oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors' position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a Nigerian federal court for enforcement of the award, and NNPC petitioned the same court to have the award set aside. On May 22, 2012, the court set aside the award. The Contractors have appealed that judgment. In June 2013, the Contractors filed a lawsuit against NNPC in the Nigerian federal high court in order to preserve their ability to seek enforcement of the PSC in the courts if necessary. In October 2014, the Contractors filed suit in the United States District Court for the Southern District of New York to enforce, if necessary, the arbitration award against NNPC assets residing within that jurisdiction. At this time, the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation's operations or financial condition.

82 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

17. Pension and Other Postretirement Benefits

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

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2014

 

2013

 

2014

 

2013

 

2014

 

2013

 

 

 

(percent)

Weighted-average assumptions used to determine

 

 

 

 

 

 

 

 

 

 

 

 

benefit obligations at December 31

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

4.00

 

5.00

 

3.10

 

4.30

 

4.00

 

5.00

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

5.30

 

5.40

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

Change in benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1

 

17,304

 

19,779

 

27,357

 

28,670

 

7,868

 

9,058

 

Service cost

 

677

 

801

 

590

 

697

 

140

 

176

 

Interest cost

 

807

 

749

 

1,138

 

1,076

 

383

 

352

 

Actuarial loss/(gain)

 

3,192

 

(1,520)

 

4,929

 

(1,454)

 

1,522

 

(1,267)

 

Benefits paid (1) (2)

 

(1,427)

 

(2,520)

 

(1,366)

 

(1,311)

 

(525)

 

(511)

 

Foreign exchange rate changes

 

 -  

 

 -  

 

(2,540)

 

(284)

 

(48)

 

(43)

 

Amendments, divestments and other

 

(24)

 

15

 

(61)

 

(37)

 

96

 

103

Benefit obligation at December 31

 

20,529

 

17,304

 

30,047

 

27,357

 

9,436

 

7,868

Accumulated benefit obligation at December 31

 

16,385

 

13,989

 

26,318

 

23,949

 

 -  

 

 -  

 

(1)   Benefit payments for funded and unfunded plans.

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

 

For selection of the discount rate for U.S. plans, several sources of information are considered, including interest rate market indicators and the discount rate determined by use of a yield curve based on high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, both of which are constructed using high-quality, local-currency-denominated bonds.

The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2016 and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $91 million and the postretirement benefit obligation by $1,070 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $69 million and the postretirement benefit obligation by $844 million.

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2014

 

2013

 

2014

 

2013

 

2014

 

2013

 

 

 

(millions of dollars)

Change in plan assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

11,190

 

12,632

 

19,283

 

18,090

 

620

 

581

 

Actual return on plan assets

 

1,497

 

617

 

3,153

 

1,604

 

41

 

64

 

Foreign exchange rate changes

 

 -  

 

 -  

 

(1,738)

 

(270)

 

 -  

 

 -  

 

Company contribution

 

1,476

 

101

 

554

 

919

 

31

 

35

 

Benefits paid (1) 

 

(1,248)

 

(2,171)

 

(912)

 

(869)

 

(224)

 

(60)

 

Other

 

 -  

 

11

 

(245)

 

(191)

 

 -  

 

 -  

Fair value at December 31

 

12,915

 

11,190

 

20,095

 

19,283

 

468

 

620

 

(1)   Benefit payments for funded plans.

83 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

 

 

Pension Benefits

 

 

 

U.S.

 

Non-U.S.

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

Balance at December 31

 

 

 

 

 

 

 

 

 

Funded plans

 

(4,590)

 

(3,547)

 

(2,113)

 

(941)

 

Unfunded plans

 

(3,024)

 

(2,567)

 

(7,839)

 

(7,133)

Total

 

(7,614)

 

(6,114)

 

(9,952)

 

(8,074)

 

The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2014

 

2013

 

2014

 

2013

 

2014

 

2013

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31  (1) 

 

(7,614)

 

(6,114)

 

(9,952)

 

(8,074)

 

(8,968)

 

(7,248)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in the consolidated balance

 

 

 

 

 

 

 

 

 

 

 

 

 

sheet consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

 -  

 

1

 

302

 

201

 

 -  

 

 -  

 

Current liabilities

 

(340)

 

(275)

 

(325)

 

(358)

 

(369)

 

(359)

 

Postretirement benefits reserves

 

(7,274)

 

(5,840)

 

(9,929)

 

(7,917)

 

(8,599)

 

(6,889)

Total recorded

 

(7,614)

 

(6,114)

 

(9,952)

 

(8,074)

 

(8,968)

 

(7,248)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

6,589

 

4,780

 

9,642

 

7,943

 

2,997

 

1,603

 

Prior service cost

 

27

 

60

 

429

 

665

 

51

 

65

Total recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

 

6,616

 

4,840

 

10,071

 

8,608

 

3,048

 

1,668

 

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

    

84 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

Pension Benefits

 

Postretirement

 

 

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

 

 

2014

 

2013

 

2012

 

2014

 

2013

 

2012

 

2014

 

2013

 

2012

Weighted-average assumptions used to

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

determine net periodic benefit cost for

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

years ended December 31

(percent)

 

Discount rate

 

5.00

 

4.00

 

5.00

 

4.30

 

3.80

 

4.00

 

5.00

 

4.00

 

5.00

 

Long-term rate of return on funded assets

 

7.25

 

7.25

 

7.25

 

6.30

 

6.40

 

6.60

 

7.25

 

7.25

 

7.25

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

5.75

 

5.40

 

5.50

 

5.40

 

5.75

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Components of net periodic benefit cost

 

(millions of dollars)

 

Service cost

 

677

 

801

 

665

 

590

 

697

 

648

 

140

 

176

 

134

 

Interest cost

 

807

 

749

 

820

 

1,138

 

1,076

 

1,145

 

383

 

352

 

380

 

Expected return on plan assets

 

(799)

 

(835)

 

(789)

 

(1,193)

 

(1,128)

 

(1,109)

 

(37)

 

(41)

 

(38)

 

Amortization of actuarial loss/(gain)

 

409

 

646

 

576

 

628

 

852

 

844

 

116

 

228

 

170

 

Amortization of prior service cost

 

8

 

7

 

7

 

120

 

117

 

117

 

14

 

21

 

34

 

Net pension enhancement and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    curtailment/settlement cost (1) 

 

276

 

723

 

333

 

 -  

 

22

 

1,540

 

 -  

 

 -  

 

 -  

Net periodic benefit cost

 

1,378

 

2,091

 

1,612

 

1,283

 

1,636

 

3,185

 

616

 

736

 

680

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in amounts recorded in accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

2,494

 

(1,302)

 

1,885

 

2,969

 

(1,938)

 

1,906

 

1,518

 

(1,290)

 

1,008

 

Amortization of actuarial (loss)/gain

 

(685)

 

(1,369)

 

(909)

 

(628)

 

(874)

 

(2,384)

 

(116)

 

(228)

 

(170)

 

Prior service cost/(credit)

 

(25)

 

 -  

 

 -  

 

(70)

 

30

 

71

 

 -  

 

 -  

 

 -  

 

Amortization of prior service (cost)/credit

 

(8)

 

(7)

 

(7)

 

(120)

 

(117)

 

(117)

 

(14)

 

(21)

 

(34)

 

Foreign exchange rate changes

 

 -  

 

 -  

 

 -  

 

(688)

 

(155)

 

271

 

(8)

 

(10)

 

3

Total recorded in other comprehensive income

 

1,776

 

(2,678)

 

969

 

1,463

 

(3,054)

 

(253)

 

1,380

 

(1,549)

 

807

Total recorded in net periodic benefit cost and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    other comprehensive income, before tax

 

3,154

 

(587)

 

2,581

 

2,746

 

(1,418)

 

2,932

 

1,996

 

(813)

 

1,487

 

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

85 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

 

 

 

Total Pension and

 

 

 

 

Other Postretirement Benefits

 

 

 

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

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

 

 

 

 

 

 

 

 

U.S. pension

 

 

(1,776)

 

2,678

 

(969)

 

Non-U.S. pension

 

 

(1,463)

 

3,054

 

253

 

Other postretirement benefits

 

 

(1,380)

 

1,549

 

(807)

Total (charge)/credit to other comprehensive income, before tax

 

 

(4,619)

 

7,281

 

(1,523)

(Charge)/credit to income tax (see Note 4)

 

 

1,549

 

(2,336)

 

393

(Charge)/credit to investment in equity companies

 

 

(81)

 

49

 

(49)

(Charge)/credit to other comprehensive income including noncontrolling

 

 

 

 

 

 

 

interests, after tax

 

 

(3,151)

 

4,994

 

(1,179)

Charge/(credit) to equity of noncontrolling interests

 

 

85

 

(279)

 

(124)

(Charge)/credit to other comprehensive income attributable to ExxonMobil

 

 

(3,066)

 

4,715

 

(1,303)

 

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in high-quality corporate and government debt securities.

Studies are periodically conducted to establish the preferred target asset allocation percentages. The target asset allocation for the U.S. benefit plans and for the non-U.S. plans in aggregate is 40 percent equity securities and 60 percent debt securities. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on early-stage venture capital of 5 percent and 3 percent, respectively.

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

86 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The 2014 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

 

 

 

 

U.S. Pension

 

 

 

Non-U.S. Pension

 

 

 

 

 

Fair Value Measurement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2014, Using:

 

 

 

at December 31, 2014, Using:

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

Significant

 

 

 

 

 

 

 

in Active

 

Significant

 

 

 

 

 

 

 

 

Markets for

Other

 

Significant

 

 

 

Markets for

 

Other

 

Significant

 

 

 

 

 

 

Identical

Observable

Unobservable

 

 

 

 

Identical

 

Observable

Unobservable

 

 

 

 

 

 

Assets

 

Inputs

 

 

Inputs

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

 

 

 

 

 

(Level 1)

 

(Level 2)

 

 

(Level 3)

 

 

Total

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Total

 

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

2,331

 (1) 

 -  

 

 

2,331

 

 

 -  

 

 

3,284

 (1) 

 -  

 

 

3,284

 

 

Non-U.S.

 

 -  

 

2,144

 (1) 

 -  

 

 

2,144

 

 

229

 (2) 

3,776

 (1) 

 -  

 

 

4,005

 

Private equity

 

 -  

 

 -  

 

 

562

 (3) 

562

 

 

 -  

 

 

 -  

 

 

535

 (3) 

535

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

4,841

 (4) 

 -  

 

 

4,841

 

 

 -  

 

 

2,686

 (4) 

 -  

 

 

2,686

 

 

Government

 

 -  

 

2,890

 (4) 

 -  

 

 

2,890

 

 

249

 (5) 

9,050

 (4) 

 -  

 

 

9,299

 

 

Asset-backed

 

 -  

 

5

 (4) 

 -  

 

 

5

 

 

 -  

 

 

146

 (4) 

 -  

 

 

146

 

Real estate funds

 

 -  

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

57

 (6) 

57

 

Cash

 

 -  

 

131

 (7) 

 -  

 

 

131

 

 

25

 

 

31

 (8) 

 -  

 

 

56

Total at fair value

 

 -  

 

12,342

 

 

562

 

 

12,904

 

 

503

 

 

18,973

 

 

592

 

 

20,068

 

Insurance contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

11

 

 

 

 

 

 

 

 

 

 

 

27

Total plan assets

 

 

 

 

 

 

 

 

 

12,915

 

 

 

 

 

 

 

 

 

 

 

20,095

 

(1)   For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2)   For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

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

(4)   For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5)   For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6)   For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(7)   For cash balances held in the form of short-term fund units that are redeemable at the measurement date, the fair value is treated as a Level 2 input.

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

   

87 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Other Postretirement

 

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2014, Using:

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

Significant

 

 

 

 

 

 

 

 

 

Markets for

 

Other

 

Significant

 

 

 

 

 

 

Identical

 

Observable

 

Unobservable

 

 

 

 

 

 

Assets

 

Inputs

 

Inputs

 

 

 

 

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

 

106

 (1) 

 -  

 

 

106

 

 

Non-U.S.

 

 -  

 

 

75

 (1) 

 -  

 

 

75

 

Private equity

 

 -  

 

 

 -  

 

 

2

 (2) 

2

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

 

103

 (3) 

 -  

 

 

103

 

 

Government

 

 -  

 

 

171

 (3) 

 -  

 

 

171

 

 

Asset-backed

 

 -  

 

 

9

 (3) 

 -  

 

 

9

 

Cash

 

 -  

 

 

2

 

 

 -  

 

 

2

Total at fair value

 

 -  

 

 

466

 

 

2

 

 

468

 

(1)     For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

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

(3)     For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

 

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

 

 

 

2014

 

 

Pension

 

 

Other

 

 

U.S.

 

 

Non-U.S.

 

 

Postretirement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Private

 

 

Private

 

Real

 

 

Private

 

 

Equity

 

 

Equity

 

Estate

 

 

Equity

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

523

 

 

 

502

 

136

 

 

9

 

Net realized gains/(losses)

 

2

 

 

 

23

 

(17)

 

 

 -  

 

Net unrealized gains/(losses)

 

89

 

 

 

31

 

8

 

 

 -  

 

Net purchases/(sales)

 

(52)

 

 

 

(21)

 

(70)

 

 

(7)

 

Fair value at December 31

 

562

 

 

 

535

 

57

 

 

2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

88 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

 

 

U.S. Pension

 

 

 

Non-U.S. Pension

 

 

 

 

 

Fair Value Measurement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2013, Using:

 

 

 

at December 31, 2013, Using:

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

Significant

 

 

 

 

 

 

 

in Active

 

Significant

 

 

 

 

 

 

 

 

Markets for

Other

 

Significant

 

 

 

Markets for

 

Other

 

Significant

 

 

 

 

 

 

Identical

Observable

Unobservable

 

 

 

 

Identical

 

Observable

Unobservable

 

 

 

 

 

 

Assets

 

Inputs

 

 

Inputs

 

 

 

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

 

 

 

 

 

(Level 1)

 

(Level 2)

 

 

(Level 3)

 

 

Total

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

Total

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

2,514

 (1) 

 -  

 

 

2,514

 

 

 -  

 

 

3,046

 (1) 

 -  

 

 

3,046

 

 

Non-U.S.

 

 -  

 

2,622

 (1) 

 -  

 

 

2,622

 

 

294

 (2) 

5,608

 (1) 

 -  

 

 

5,902

 

Private equity

 

 -  

 

 -  

 

 

523

 (3) 

523

 

 

 -  

 

 

 -  

 

 

502

 (3) 

502

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

3,430

 (4) 

 -  

 

 

3,430

 

 

 -  

 

2,125

 (4) 

 -  

 

 

2,125

 

 

Government

 

 -  

 

2,056

 (4) 

 -  

 

 

2,056

 

 

272

 (5) 

7,100

 (4) 

 -  

 

 

7,372

 

 

Asset-backed

 

 -  

 

6

 (4) 

 -  

 

 

6

 

 

 -  

 

 

103

 (4) 

 -  

 

 

103

 

Real estate funds

 

 -  

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

136

 (6) 

136

 

Cash

 

 -  

 

27

 (7) 

 -  

 

 

27

 

 

57

 

 

20

 (8) 

 -  

 

 

77

Total at fair value

 

 -  

 

10,655

 

 

523

 

 

11,178

 

 

623

 

 

18,002

 

 

638

 

 

19,263

 

Insurance contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

12

 

 

 

 

 

 

 

 

 

 

 

20

Total plan assets

 

 

 

 

 

 

 

 

 

11,190

 

 

 

 

 

 

 

 

 

 

 

19,283

 

(1)   For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2)   For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

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

(4)   For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5)   For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6)   For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(7)   For cash balances held in the form of short-term fund units that are redeemable at the measurement date, the fair value is treated as a Level 2 input.

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

   

  

89 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Other Postretirement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2013, Using:

 

 

 

 

 

 

Quoted

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

Significant

 

 

 

 

 

 

 

 

 

Markets for

 

Other

 

Significant

 

 

 

 

 

 

Identical

 

Observable

 

Unobservable

 

 

 

 

 

 

Assets

 

Inputs

 

Inputs

 

 

 

 

 

 

(Level 1)

 

(Level 2)

 

(Level 3)

 

Total

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

 

157

 (1) 

 -  

 

 

157

 

 

Non-U.S.

 

 -  

 

 

149

 (1) 

 -  

 

 

149

 

Private equity

 

 -  

 

 

 -  

 

 

9

 (2) 

9

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

 

129

 (3) 

 -  

 

 

129

 

 

Government

 

 -  

 

 

168

 (3) 

 -  

 

 

168

 

 

Asset-backed

 

 -  

 

 

4

 (3) 

 -  

 

 

4

 

Cash

 

 -  

 

 

4

 

 

 -  

 

 

4

Total at fair value

 

 -  

 

 

611

 

 

9

 

 

620

 

(1)   For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

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

(3)   For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

 

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

 

 

 

2013

 

 

Pension

 

 

Other

 

 

U.S.

 

 

Non-U.S.

 

 

Postretirement

 

 

Private

 

 

 

Private

 

Real

 

 

Private

 

 

Equity

 

 

Equity

 

Estate

 

 

Equity

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

489

 

 

 

448

 

293

 

 

7

 

Net realized gains/(losses)

 

(1)

 

 

 

11

 

(13)

 

 

 -  

 

Net unrealized gains/(losses)

 

86

 

 

 

57

 

10

 

 

3

 

Net purchases/(sales)

 

(51)

 

 

 

(14)

 

(154)

 

 

(1)

 

Fair value at December 31

 

523

 

 

 

502

 

136

 

 

9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

90 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

 

Pension Benefits

 

 

U.S.

 

Non-U.S.

 

 

 

2014

 

2013

 

 

2014

 

2013

 

 

(millions of dollars)

For funded  pension plans with an accumulated benefit obligation

 

 

 

 

 

 

 

 

 

 

in excess of plan assets:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

17,505

 

14,737

 

 

5,031

 

891

 

Accumulated benefit obligation

 

14,493

 

12,342

 

 

4,590

 

689

 

Fair value of plan assets

 

12,915

 

11,189

 

 

3,890

 

611

 

 

 

 

 

 

 

 

 

 

 

For unfunded  pension plans:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

3,024

 

2,567

 

 

7,839

 

7,133

 

Accumulated benefit obligation

 

1,892

 

1,647

 

 

6,573

 

6,070

 

 

 

 

 

 

 

 

Other

 

 

Pension Benefits

 

Postretirement

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

(millions of dollars)

Estimated 2015 amortization from accumulated other comprehensive income:

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)  (1) 

 

1,001

 

753

 

 

211

 

Prior service cost  (2) 

 

6

 

105

 

 

14

 

(1)   The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service period of active plan participants.

(2)   The Corporation amortizes prior service cost on a straight-line basis as permitted under authoritative guidance for defined benefit pension and other postretirement benefit plans.

 

 

 

 

Pension Benefits

 

Other Postretirement Benefits

 

 

 

 

 

 

 

 

 

Medicare

 

 

 

U.S.

 

Non-U.S.

 

Gross

 

Subsidy Receipt

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Contributions expected in 2015

 

 -  

 

560

 

 -  

 

 

 -  

 

Benefit payments expected in:

 

 

 

 

 

 

 

 

 

 

 

2015

 

1,628

 

1,194

 

467

 

 

24

 

 

2016

 

1,554

 

1,213

 

479

 

 

25

 

 

2017

 

1,529

 

1,278

 

490

 

 

26

 

 

2018

 

1,445

 

1,298

 

499

 

 

28

 

 

2019

 

1,410

 

1,339

 

507

 

 

29

 

 

2020 - 2024

 

6,714

 

6,988

 

2,613

 

 

172

 

 

18. Disclosures about Segments and Related Information

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

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

Earnings after income tax include transfers at estimated market prices.

91 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt-related interest expense of $129 million and $202 million in 2014 and 2012, respectively. For 2013, non-debt-related interest expense was a net credit of $123 million, primarily reflecting the effect of credits from the favorable resolution of prior year tax positions.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 

Upstream

 

Downstream

 

Chemical

 

 

and

Corporate

 

U.S.

Non-U.S.

 

U.S.

Non-U.S.

 

U.S.

Non-U.S.

 

Financing

Total

 

 

(millions of dollars)

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

5,197

 

22,351

 

 

1,618

 

1,427

 

 

2,804

 

1,511

 

 

(2,388)

 

32,520

Earnings of equity companies included above

 

1,235

 

10,859

 

 

29

 

82

 

 

186

 

1,377

 

 

(445)

 

13,323

Sales and other operating revenue (1) 

 

14,826

 

22,336

 

 

118,771

 

199,976

 

 

15,115

 

23,063

 

 

18

 

394,105

Intersegment revenue

 

7,723

 

38,846

 

 

17,281

 

44,231

 

 

10,117

 

8,098

 

 

274

 

 -  

Depreciation and depletion expense

 

5,139

 

8,523

 

 

654

 

1,228

 

 

370

 

645

 

 

738

 

17,297

Interest revenue

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

75

 

75

Interest expense

 

40

 

17

 

 

6

 

4

 

 

 -  

 

 -  

 

 

219

 

286

Income taxes

 

1,300

 

15,165

 

 

610

 

968

 

 

1,032

 

358

 

 

(1,418)

 

18,015

Additions to property, plant and equipment

 

9,098

 

19,225

 

 

1,050

 

1,356

 

 

1,564

 

564

 

 

1,399

 

34,256

Investments in equity companies

 

5,089

 

10,877

 

 

69

 

1,006

 

 

258

 

3,026

 

 

(308)

 

20,017

Total assets

 

92,555

 

161,033

 

 

18,371

 

33,299

 

 

8,798

 

18,449

 

 

16,988

 

349,493

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

4,191

 

22,650

 

 

2,199

 

1,250

 

 

2,755

 

1,073

 

 

(1,538)

 

32,580

Earnings of equity companies included above

 

1,576

 

11,627

 

 

(460)

 

22

 

 

189

 

1,422

 

 

(449)

 

13,927

Sales and other operating revenue (1)

 

13,712

 

25,349

 

 

123,802

 

218,904

 

 

15,295

 

23,753

 

 

21

 

420,836

Intersegment revenue

 

8,343

 

45,761

 

 

20,781

 

52,624

 

 

11,993

 

8,232

 

 

285

 

 -  

Depreciation and depletion expense

 

5,170

 

8,277

 

 

633

 

1,390

 

 

378

 

632

 

 

702

 

17,182

Interest revenue

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

87

 

87

Interest expense

 

30

 

26

 

 

7

 

8

 

 

 1  

 

 -  

 

 

(63)

 

9

Income taxes

 

2,197

 

21,554

 

 

721

 

481

 

 

989

 

363

 

 

(2,042)

 

24,263

Additions to property, plant and equipment

 

7,480

 

26,075

 

 

616

 

1,072

 

 

840

 

272

 

 

1,386

 

37,741

Investments in equity companies

 

4,975

 

9,740

 

 

62

 

1,749

 

 

217

 

3,103

 

 

(227)

 

19,619

Total assets

 

88,698

 

157,465

 

 

19,261

 

40,661

 

 

7,816

 

19,659

 

 

13,248

 

346,808

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

3,925

 

25,970

 

 

3,575

 

9,615

 

 

2,220

 

1,678

 

 

(2,103)

 

44,880

Earnings of equity companies included above

 

1,759

 

11,900

 

 

6

 

387

 

 

183

 

1,267

 

 

(492)

 

15,010

Sales and other operating revenue (1)

 

11,039

 

27,673

 

 

125,088

 

248,959

 

 

14,723

 

24,003

 

 

24

 

451,509

Intersegment revenue

 

8,764

 

47,507

 

 

20,963

 

62,130

 

 

12,409

 

9,750

 

 

258

 

 -  

Depreciation and depletion expense

 

5,104

 

7,340

 

 

594

 

1,280

 

 

376

 

508

 

 

686

 

15,888

Interest revenue

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

117

 

117

Interest expense

 

37

 

13

 

 

3

 

36

 

 

 -  

 

(1)

 

 

239

 

327

Income taxes

 

2,025

 

25,362

 

 

1,811

 

1,892

 

 

755

 

232

 

 

(1,032)

 

31,045

Additions to property, plant and equipment

 

9,697

 

21,769

 

 

480

 

1,153

 

 

338

 

659

 

 

1,083

 

35,179

Investments in equity companies

 

4,020

 

9,147

 

 

195

 

2,069

 

 

233

 

3,143

 

 

(277)

 

18,530

Total assets

 

86,146

 

140,848

 

 

18,451

 

40,956

 

 

7,238

 

18,886

 

 

21,270

 

333,795

 

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

   

92 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Geographic

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue  (1) 

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

148,713

 

152,820

 

150,865

Non-U.S.

 

245,392

 

268,016

 

300,644

 

Total

 

394,105

 

420,836

 

451,509

 

 

 

 

 

 

 

 

Significant non-U.S. revenue sources include:

 

 

 

 

 

 

 

Canada

 

36,072

 

35,924

 

34,325

 

United Kingdom

 

31,346

 

34,061

 

33,600

 

Belgium

 

20,953

 

20,973

 

23,567

 

Italy

 

18,880

 

19,273

 

18,228

 

France

 

17,639

 

18,444

 

19,601

 

Singapore

 

15,407

 

15,623

 

14,606

 

Germany

 

14,816

 

15,701

 

15,871

 

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

 

Long-lived assets

 

2014

 

2013

 

2012

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

104,000

 

98,271

 

94,336

Non-U.S.

 

148,668

 

145,379

 

132,613

 

Total

 

252,668

 

243,650

 

226,949

 

 

 

 

 

 

 

 

Significant non-U.S. long-lived assets include:

 

 

 

 

 

 

 

Canada

 

43,858

 

41,522

 

31,979

 

Australia

 

15,328

 

14,258

 

13,415

 

Nigeria

 

12,265

 

12,343

 

12,216

 

Singapore

 

9,620

 

9,570

 

9,700

 

Kazakhstan

 

9,138

 

8,530

 

7,785

 

Angola

 

9,057

 

8,262

 

8,238

 

Papua New Guinea

 

6,099

 

5,768

 

4,599

 

Norway

 

5,139

 

6,542

 

7,040

93 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

19. Income, Sales-Based and Other Taxes

 

 

 

 

 

 

 

 

2014

 

 

 

 

 

2013

 

 

 

 

 

2012

 

 

 

 

 

 

 

U.S.

Non-U.S.

Total

 

U.S.

Non-U.S.

Total

 

U.S.

Non-U.S.

Total

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

Income tax expense

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal and non-U.S.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

1,456

 

14,755

 

16,211

 

1,073

 

22,115

 

23,188

 

1,791

 

25,650

 

27,441

 

 

Deferred - net

 

900

 

1,398

 

2,298

 

(116)

 

757

 

641

 

1,097

 

1,816

 

2,913

 

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

 

5

 

 -  

 

5

 

37

 

 -  

 

37

 

89

 

 -  

 

89

 

 

 

Total federal and non-U.S.

 

2,361

 

16,153

 

18,514

 

994

 

22,872

 

23,866

 

2,977

 

27,466

 

30,443

 

State (1) 

 

(499)

 

 -  

 

(499)

 

397

 

 -  

 

397

 

602

 

 -  

 

602

 

 

 

Total income tax expense

 

1,862

 

16,153

 

18,015

 

1,391

 

22,872

 

24,263

 

3,579

 

27,466

 

31,045

Sales-based taxes

 

6,310

 

23,032

 

29,342

 

5,992

 

24,597

 

30,589

 

5,785

 

26,624

 

32,409

All other taxes and duties

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other taxes and duties

 

378

 

31,908

 

32,286

 

955

 

32,275

 

33,230

 

1,406

 

34,152

 

35,558

 

Included in production and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

manufacturing expenses

 

1,454

 

1,179

 

2,633

 

1,318

 

1,182

 

2,500

 

1,242

 

1,308

 

2,550

 

Included in SG&A expenses

 

155

 

441

 

596

 

150

 

516

 

666

 

154

 

595

 

749

 

 

Total other taxes and duties

 

1,987

 

33,528

 

35,515

 

2,423

 

33,973

 

36,396

 

2,802

 

36,055

 

38,857

 

 

 

Total

 

10,159

 

72,713

 

82,872

 

9,806

 

81,442

 

91,248

 

12,166

 

90,145

 

102,311

 

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

 

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits of $40 million in 2014 and $310 million in 2013 and a net charge of $244 million in 2012 for the effect of changes in tax laws and rates.

 

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2014, 2013 and 2012 is as follows:

 

 

 

 

 

2014

 

2013

 

2012

 

 

 

 

(millions of dollars)

Income before income taxes

 

 

 

 

 

 

 

United States

 

9,080

 

9,746

 

11,222

 

Non-U.S.

 

42,550

 

47,965

 

67,504

 

 

Total

 

51,630

 

57,711

 

78,726

Theoretical tax

 

18,071

 

20,199

 

27,554

Effect of equity method of accounting

 

(4,663)

 

(4,874)

 

(5,254)

Non-U.S. taxes in excess of theoretical U.S. tax

 

5,442

 

10,528

 

8,434

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

 

5

 

37

 

89

State taxes, net of federal tax benefit

 

(324)

 

258

 

391

Other

 

(516)

 

(1,885)

 

(169)

 

 

Total income tax expense

 

18,015

 

24,263

 

31,045

 

 

 

 

 

 

 

 

 

Effective tax rate calculation

 

 

 

 

 

 

Income taxes

 

18,015

 

24,263

 

31,045

ExxonMobil share of equity company income taxes

 

5,678

 

6,061

 

5,859

 

 

Total income taxes

 

23,693

 

30,324

 

36,904

Net income including noncontrolling interests

 

33,615

 

33,448

 

47,681

 

 

Total income before taxes

 

57,308

 

63,772

 

84,585

 

 

 

 

 

 

 

 

 

Effective income tax rate

 

41%

 

48%

 

44%

94 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

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

 

Tax effects of temporary differences for:

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

Property, plant and equipment

 

51,643

 

50,884

Other liabilities

 

4,359

 

3,474

 

Total deferred tax liabilities

 

56,002

 

54,358

 

 

 

 

 

 

Pension and other postretirement benefits

 

(8,140)

 

(6,573)

Asset retirement obligations

 

(6,162)

 

(6,083)

Tax loss carryforwards

 

(4,099)

 

(3,393)

Other assets

 

(6,446)

 

(6,246)

 

Total deferred tax assets

 

(24,847)

 

(22,295)

 

 

 

 

 

 

Asset valuation allowances

 

2,570

 

2,491

 

Net deferred tax liabilities

 

33,725

 

34,554

 

In 2014, asset valuation allowances of $2,570 million increased by $79 million and included additional net provisions of $340 million and effects of foreign currency translation of $(261) million. 

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

 

Balance sheet classification

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

Other current assets

 

(2,001)

 

(3,575)

Other assets, including intangibles, net

 

(3,955)

 

(2,822)

Accounts payable and accrued liabilities

 

451

 

421

Deferred income tax liabilities

 

39,230

 

40,530

 

Net deferred tax liabilities

 

33,725

 

34,554

 

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

95 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

  

 

Gross unrecognized tax benefits

2014

 

2013

 

2012

 

 

(millions of dollars)

 

 

 

 

 

 

 

Balance at January 1

7,838

 

7,663

 

4,922

 

Additions based on current year's tax positions

1,454

 

1,460

 

1,662

 

Additions for prior years' tax positions

448

 

464

 

2,559

 

Reductions for prior years' tax positions

(532)

 

(249)

 

(535)

 

Reductions due to lapse of the statute of limitations

(117)

 

(588)

 

(79)

 

Settlements with tax authorities

(43)

 

(849)

 

(855)

 

Foreign exchange effects/other

(62)

 

(63)

 

(11)

Balance at December 31

8,986

 

7,838

 

7,663

 

The gross unrecognized tax benefit balances shown above are predominantly related to tax positions that would reduce the Corporation’s effective tax rate if the positions are favorably resolved. Unfavorable resolution of these tax positions generally would not increase the effective tax rate. The 2014, 2013 and 2012 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income.

Resolution of these tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 30 percent in the next 12 months, with no material impact on the Corporation’s net income.

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

 

 

Country of Operation

Open Tax Years

 

 

Abu Dhabi

2012 - 2014

 

 

Angola

2009 - 2014

 

 

Australia:

2000 - 2003

 

 

 

2005

 

 

 

2008 - 2014

 

 

Canada

2007 - 2014

 

 

Equatorial Guinea

2007 - 2014

 

 

Malaysia

2008 - 2014

 

 

Nigeria

2004 - 2014

 

 

Norway

2005 - 2014

 

 

Qatar

2008 - 2014

 

 

Russia

2011 - 2014

 

 

United Kingdom

2010 - 2014

 

 

United States

2006 - 2014

 

 

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

The Corporation incurred $42 million in interest expense on income tax reserves in 2014. For 2013, the Corporation’s net interest expense was a credit of $207 million, reflecting the effect of credits from the favorable resolution of prior year tax positions. The Corporation incurred $46 million in interest expense in 2012. The related interest payable balances were $205 million and $156 million at December 31, 2014, and 2013, respectively.

  

 

96 


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 $3,223 million in 2014, $886 million in 2013, and $2,832 million in 2012. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules.

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

United

 

South

 

 

 

 

 

 

 

Australia/

 

 

Results of Operations

 

States

 

America

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

9,453

 

2,841

 

4,608

 

1,943

 

4,383

 

1,374

 

24,602

 

 

Transfers

 

5,554

 

5,417

 

5,206

 

14,884

 

7,534

 

1,553

 

40,148

 

 

 

 

15,007

 

8,258

 

9,814

 

16,827

 

11,917

 

2,927

 

64,750

 

Production costs excluding taxes

 

4,637

 

4,251

 

3,117

 

2,248

 

1,568

 

583

 

16,404

 

Exploration expenses

 

231

 

363

 

274

 

427

 

287

 

87

 

1,669

 

Depreciation and depletion

 

4,877

 

1,193

 

1,929

 

3,387

 

1,242

 

454

 

13,082

 

Taxes other than income

 

1,116

 

160

 

412

 

1,539

 

1,542

 

399

 

5,168

 

Related income tax

 

1,208

 

524

 

2,954

 

5,515

 

4,882

 

435

 

15,518

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

2,938

 

1,767

 

1,128

 

3,711

 

2,396

 

969

 

12,909

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2014 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,239

 

-

 

4,923

 

-

 

20,028

 

-

 

26,190

 

 

Transfers

 

924

 

-

 

63

 

-

 

685

 

-

 

1,672

 

 

 

 

2,163

 

-

 

4,986

 

-

 

20,713

 

-

 

27,862

 

Production costs excluding taxes

 

620

 

-

 

602

 

-

 

548

 

-

 

1,770

 

Exploration expenses

 

61

 

-

 

22

 

-

 

219

 

-

 

302

 

Depreciation and depletion

 

253

 

-

 

195

 

-

 

383

 

-

 

831

 

Taxes other than income

 

57

 

-

 

2,650

 

-

 

5,184

 

-

 

7,891

 

Related income tax

 

-

 

-

 

553

 

-

 

5,099

 

-

 

5,652

 

Results of producing activities for equity companies

 

1,172

 

-

 

964

 

-

 

9,280

 

-

 

11,416

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

4,110

 

1,767

 

2,092

 

3,711

 

11,676

 

969

 

24,325

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

97 


   

  

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United

 

South

 

 

 

 

 

 

Australia/

 

Results of Operations

 

States

 

America

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

8,371

 

2,252

 

5,649

 

3,079

 

5,427

 

730

 

25,508

 

 

Transfers

 

6,505

 

5,666

 

5,654

 

15,738

 

8,936

 

1,405

 

43,904

 

 

 

 

14,876

 

7,918

 

11,303

 

18,817

 

14,363

 

2,135

 

69,412

 

Production costs excluding taxes

 

4,191

 

3,965

 

2,859

 

2,396

 

1,763

 

654

 

15,828

 

Exploration expenses

 

394

 

386

 

245

 

288

 

571

 

92

 

1,976

 

Depreciation and depletion

 

4,926

 

989

 

1,881

 

3,269

 

1,680

 

334

 

13,079

 

Taxes other than income

 

1,566

 

94

 

474

 

1,583

 

1,794

 

427

 

5,938

 

Related income tax

 

1,788

 

542

 

4,124

 

6,841

 

5,709

 

202

 

19,206

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

2,011

 

1,942

 

1,720

 

4,440

 

2,846

 

426

 

13,385

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,320

 

 -  

 

6,768

 

 -  

 

21,463

 

 -  

 

29,551

 

 

Transfers

 

1,034

 

 -  

 

64

 

 -  

 

6,091

 

 -  

 

7,189

 

 

 

 

2,354

 

 -  

 

6,832

 

 -  

 

27,554

 

 -  

 

36,740

 

Production costs excluding taxes

 

551

 

 -  

 

459

 

 -  

 

660

 

 -  

 

1,670

 

Exploration expenses

 

19

 

 -  

 

15

 

 -  

 

426

 

 -  

 

460

 

Depreciation and depletion

 

207

 

 -  

 

169

 

 -  

 

955

 

 -  

 

1,331

 

Taxes other than income

 

51

 

 -  

 

3,992

 

 -  

 

7,352

 

 -  

 

11,395

 

Related income tax

 

 -  

 

 -  

 

832

 

 -  

 

8,482

 

 -  

 

9,314

 

Results of producing activities for equity companies

 

1,526

 

 -  

 

1,365

 

 -  

 

9,679

 

 -  

 

12,570

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

3,537

 

1,942

 

3,085

 

4,440

 

12,525

 

426

 

25,955

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

6,977

 

1,804

 

5,835

 

3,672

 

6,536

 

1,275

 

26,099

 

 

Transfers

 

6,996

 

5,457

 

6,366

 

16,905

 

9,241

 

932

 

45,897

 

 

 

 

13,973

 

7,261

 

12,201

 

20,577

 

15,777

 

2,207

 

71,996

 

Production costs excluding taxes

 

4,044

 

3,079

 

2,443

 

2,395

 

1,606

 

488

 

14,055

 

Exploration expenses

 

391

 

292

 

274

 

234

 

513

 

136

 

1,840

 

Depreciation and depletion

 

4,862

 

848

 

1,559

 

2,879

 

1,785

 

264

 

12,197

 

Taxes other than income

 

1,963

 

89

 

513

 

1,702

 

2,248

 

446

 

6,961

 

Related income tax

 

1,561

 

720

 

5,413

 

8,091

 

6,616

 

281

 

22,682

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

1,152

 

2,233

 

1,999

 

5,276

 

3,009

 

592

 

14,261

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2012 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

1,284

 

 -  

 

6,380

 

 -  

 

20,017

 

 -  

 

27,681

 

 

Transfers

 

1,108

 

 -  

 

67

 

 -  

 

5,693

 

 -  

 

6,868

 

 

 

 

2,392

 

 -  

 

6,447

 

 -  

 

25,710

 

 -  

 

34,549

 

Production costs excluding taxes

 

467

 

 -  

 

369

 

 -  

 

484

 

 -  

 

1,320

 

Exploration expenses

 

9

 

 -  

 

17

 

 -  

 

 -  

 

 -  

 

26

 

Depreciation and depletion

 

176

 

 -  

 

152

 

 -  

 

676

 

 -  

 

1,004

 

Taxes other than income

 

42

 

 -  

 

3,569

 

 -  

 

6,658

 

 -  

 

10,269

 

Related income tax

 

 -  

 

 -  

 

894

 

 -  

 

8,234

 

 -  

 

9,128

 

Results of producing activities for equity companies

 

1,698

 

 -  

 

1,446

 

 -  

 

9,658

 

 -  

 

12,802

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

2,850

 

2,233

 

3,445

 

5,276

 

12,667

 

592

 

27,063

98 


   

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $12,856 million less at year-end 2014 and $13,667 million less at year-end 2013 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 9. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations are included in the capitalized costs in accordance with Financial Accounting Standards Board rules.

 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United

 

South

 

 

 

 

 

 

Australia/

 

Capitalized Costs

 

 

States

 

America

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

14,664

 

2,598

 

161

 

876

 

1,660

 

808

 

20,767

 

 

- Unproved

 

24,062

 

4,824

 

74

 

615

 

601

 

136

 

30,312

 

 

Total property costs

 

 

38,726

 

7,422

 

235

 

1,491

 

2,261

 

944

 

51,079

 

Producing assets

 

 

79,138

 

32,635

 

39,996

 

44,700

 

30,219

 

10,051

 

236,739

 

Incomplete construction

 

 

7,051

 

15,344

 

2,114

 

6,075

 

10,163

 

4,621

 

45,368

 

 

Total capitalized costs

 

 

124,915

 

55,401

 

42,345

 

52,266

 

42,643

 

15,616

 

333,186

 

Accumulated depreciation and depletion

 

43,031

 

15,197

 

32,608

 

27,995

 

17,273

 

4,630

 

140,734

 

Net capitalized costs for consolidated subsidiaries

 

81,884

 

40,204

 

9,737

 

24,271

 

25,370

 

10,986

 

192,452

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

78

 

 -  

 

4

 

 -  

 

 -  

 

 -  

 

82

 

 

- Unproved

 

35

 

 -  

 

 -  

 

 -  

 

59

 

 -  

 

94

 

 

Total property costs

 

 

113

 

 -  

 

4

 

 -  

 

59

 

 -  

 

176

 

Producing assets

 

 

5,538

 

 -  

 

5,309

 

 -  

 

8,500

 

 -  

 

19,347

 

Incomplete construction

 

 

473

 

 -  

 

251

 

 -  

 

2,972

 

 -  

 

3,696

 

 

Total capitalized costs

 

 

6,124

 

 -  

 

5,564

 

 -  

 

11,531

 

 -  

 

23,219

 

Accumulated depreciation and depletion

 

1,872

 

 -  

 

4,205

 

 -  

 

5,095

 

 -  

 

11,172

 

Net capitalized costs for equity companies

 

4,252

 

 -  

 

1,359

 

 -  

 

6,436

 

 -  

 

12,047

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

13,881

 

3,595

 

188

 

874

 

1,620

 

863

 

21,021

 

 

- Unproved

 

23,945

 

5,390

 

61

 

583

 

701

 

146

 

30,826

 

 

Total property costs

 

 

37,826

 

8,985

 

249

 

1,457

 

2,321

 

1,009

 

51,847

 

Producing assets

 

 

74,743

 

34,487

 

44,161

 

40,424

 

30,082

 

7,973

 

231,870

 

Incomplete construction

 

 

5,640

 

11,811

 

2,219

 

5,913

 

8,387

 

4,194

 

38,164

 

 

Total capitalized costs

 

 

118,209

 

55,283

 

46,629

 

47,794

 

40,790

 

13,176

 

321,881

 

Accumulated depreciation and depletion

 

39,505

 

16,827

 

35,108

 

24,570

 

17,455

 

4,529

 

137,994

 

Net capitalized costs for consolidated subsidiaries

 

78,704

 

38,456

 

11,521

 

23,224

 

23,335

 

8,647

 

183,887

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

77

 

 -  

 

5

 

 -  

 

 -  

 

 -  

 

82

 

 

- Unproved

 

40

 

 -  

 

 -  

 

 -  

 

17

 

 -  

 

57

 

 

Total property costs

 

 

117

 

 -  

 

5

 

 -  

 

17

 

 -  

 

139

 

Producing assets

 

 

5,206

 

 -  

 

6,039

 

 -  

 

8,397

 

 -  

 

19,642

 

Incomplete construction

 

 

416

 

 -  

 

201

 

 -  

 

1,452

 

 -  

 

2,069

 

 

Total capitalized costs

 

 

5,739

 

 -  

 

6,245

 

 -  

 

9,866

 

 -  

 

21,850

 

Accumulated depreciation and depletion

 

1,646

 

 -  

 

4,778

 

 -  

 

4,706

 

 -  

 

11,130

 

Net capitalized costs for equity companies

 

4,093

 

 -  

 

1,467

 

 -  

 

5,160

 

 -  

 

10,720

99 


   

Oil and Gas Exploration and Production Costs (continued)

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2014 were $29,115 million, down $4,508 million from 2013, due primarily to lower property acquisition costs and development costs. In 2013 costs were $33,623 million, up $2,477 million from 2012, due primarily to higher property acquisition costs partially offset by lower exploration costs. Total equity company costs incurred in 2014 were $2,677 million, up $335 million from 2013, due primarily to exploration costs.

 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

Costs Incurred in Property Acquisitions,

 

United

 

South

 

 

 

 

 

 

Australia/

 

Exploration and Development Activities

 

States

 

America

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

During 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

80

 

 -  

 

 -  

 

 -  

 

41

 

 -  

 

121

 

 

 

- Unproved

 

1,253

 

3

 

19

 

34

 

 -  

 

 -  

 

1,309

 

 

Exploration costs

 

 

319

 

453

 

458

 

628

 

467

 

121

 

2,446

 

 

Development costs

 

 

7,540

 

6,877

 

1,390

 

4,255

 

3,321

 

1,856

 

25,239

 

 

Total costs incurred for consolidated subsidiaries

 

9,192

 

7,333

 

1,867

 

4,917

 

3,829

 

1,977

 

29,115

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 

 

- Unproved

 

 -  

 

 -  

 

 -  

 

 -  

 

42

 

 -  

 

42

 

 

Exploration costs

 

 

17

 

 -  

 

45

 

 -  

 

964

 

 -  

 

1,026

 

 

Development costs

 

 

490

 

 -  

 

233

 

 -  

 

886

 

 -  

 

1,609

 

 

Total costs incurred for equity companies

 

507

 

 -  

 

278

 

 -  

 

1,892

 

 -  

 

2,677

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

93

 

67

 

 -  

 

 -  

 

47

 

 -  

 

207

 

 

 

- Unproved

 

533

 

4,270

 

 -  

 

153

 

 -  

 

4

 

4,960

 

 

Exploration costs

 

 

557

 

485

 

277

 

361

 

598

 

111

 

2,389

 

 

Development costs

 

 

6,919

 

8,527

 

2,117

 

3,278

 

3,493

 

1,733

 

26,067

 

 

Total costs incurred for consolidated subsidiaries

 

8,102

 

13,349

 

2,394

 

3,792

 

4,138

 

1,848

 

33,623

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

2

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

2

 

 

 

- Unproved

 

 -  

 

 -  

 

 -  

 

 -  

 

17

 

 -  

 

17

 

 

Exploration costs

 

 

60

 

 -  

 

29

 

 -  

 

494

 

 -  

 

583

 

 

Development costs

 

 

720

 

 -  

 

192

 

 -  

 

828

 

 -  

 

1,740

 

 

Total costs incurred for equity companies

 

782

 

 -  

 

221

 

 -  

 

1,339

 

 -  

 

2,342

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

192

 

2

 

95

 

 -  

 

43

 

 -  

 

332

 

 

 

- Unproved

 

1,717

 

74

 

24

 

15

 

 -  

 

31

 

1,861

 

 

Exploration costs

 

 

601

 

405

 

454

 

520

 

554

 

248

 

2,782

 

 

Development costs

 

 

7,172

 

7,601

 

2,637

 

3,081

 

3,347

 

2,333

 

26,171

 

 

Total costs incurred for consolidated subsidiaries

 

9,682

 

8,082

 

3,210

 

3,616

 

3,944

 

2,612

 

31,146

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

 

 

- Unproved

 

14

 

 -  

 

 -  

 

 -  

 

 -  

 

 -  

 

14

 

 

Exploration costs

 

 

45

 

 -  

 

34

 

 -  

 

 -  

 

 -  

 

79

 

 

Development costs

 

 

504

 

 -  

 

156

 

 -  

 

651

 

 -  

 

1,311

 

 

Total costs incurred for equity companies

 

563

 

 -  

 

190

 

 -  

 

651

 

 -  

 

1,404

100 


   

Oil and Gas Reserves

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

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

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

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

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

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

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

Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2014 that were associated with production sharing contract arrangements was 11 percent of liquids, 9 percent of natural gas and 10 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).

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

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

The changes, between 2013 year-end proved reserves and 2014 year-end proved reserves, primarily reflect the revisions, extensions and discoveries in Canada and the United States.

101 


   

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

Crude Oil

 

Liquids (1) 

 

Bitumen

 

Synthetic Oil

 

 

 

United

Canada/

 

 

Australia/

 

 

 

Canada/

 

 

Canada/

 

 

 

 

States

S. Amer.

Europe

Africa

Asia

Oceania

Total

Worldwide

S. Amer.

 

 

S. Amer.

 

Total

 

 

(millions of barrels)

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2012

1,660

118

317

1,463

1,721

170

5,449

 

905

 

3,106

 

 

653

 

10,113

 

Revisions

25

33

14

20

(10)

5

87

 

3

 

265

 

 

(29)

 

326

 

Improved recovery

6

-

-

-

1

-

7

 

-

 

-

 

 

-

 

7

 

Purchases

163

-

20

-

-

-

183

 

36

 

-

 

 

-

 

219

 

Sales

(15)

(1)

(8)

(58)

-

-

(82)

 

(4)

 

-

 

 

-

 

(86)

 

Extensions/discoveries

166

138

8

41

9

-

362

 

164

 

234

 

 

-

 

760

 

Production

(100)

(18)

(62)

(173)

(117)

(12)

(482)

 

(73)

 

(45)

 

 

(25)

 

(625)

December 31, 2012

1,905

270

289

1,293

1,604

163

5,524

 

1,031

 

3,560

 

 

599

 

10,714

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2012

348

-

29

-

1,255

-

1,632

 

483

 

-

 

 

-

 

2,115

 

Revisions

(2)

-

1

-

131

-

130

 

15

 

-

 

 

-

 

145

 

Improved recovery

16

-

-

-

-

-

16

 

-

 

-

 

 

-

 

16

 

Purchases

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Production

(22)

-

(2)

-

(126)

-

(150)

 

(24)

 

-

 

 

-

 

(174)

December 31, 2012

340

-

28

-

1,260

-

1,628

 

474

 

-

 

 

-

 

2,102

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2012

2,245

270

317

1,293

2,864

163

7,152

 

1,505

 

3,560

 

 

599

 

12,816

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2013

1,905

270

289

1,293

1,604

163

5,524

 

1,031

 

3,560

 

 

599

 

10,714

 

Revisions

21

20

13

13

411

3

481

 

(1)

 

124

 

 

4

 

608

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

15

15

-

-

-

-

30

 

27

 

-

 

 

-

 

57

 

Sales

(18)

-

-

-

-

-

(18)

 

(6)

 

-

 

 

-

 

(24)

 

Extensions/discoveries

188

-

-

52

262

-

502

 

39

 

-

 

 

-

 

541

 

Production

(103)

(21)

(57)

(165)

(114)

(11)

(471)

 

(67)

 

(54)

 

 

(24)

 

(616)

December 31, 2013

2,008

284

245

1,193

2,163

155

6,048

 

1,023

 

3,630

 

 

579

 

11,280

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2013

340

-

28

-

1,260

-

1,628

 

474

 

-

 

 

-

 

2,102

 

Revisions

12

-

2

-

21

-

35

 

8

 

-

 

 

-

 

43

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Production

(22)

-

(2)

-

(136)

-

(160)

 

(26)

 

-

 

 

-

 

(186)

December 31, 2013

330

-

28

-

1,145

-

1,503

 

456

 

-

 

 

-

 

1,959

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2013

2,338

284

273

1,193

3,308

155

7,551

 

1,479

 

3,630

 

 

579

 

13,239

 

(See footnote on next page)

102 


   

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

Crude Oil

 

Liquids (1) 

 

Bitumen

 

Synthetic Oil

 

 

 

United

Canada/

 

 

Australia/

 

 

 

Canada/

 

 

Canada/

 

 

 

 

States

S. Amer.

Europe

Africa

Asia

Oceania

Total

Worldwide

S. Amer.

 

 

S. Amer.

 

Total

 

 

(millions of barrels)

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2014

2,008

284

245

1,193

2,163

155

6,048

 

1,023

 

3,630

 

 

579

 

11,280

 

Revisions

37

23

9

42

42

-

153

 

59

 

669

 

 

(23)

 

858

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

42

-

-

-

-

-

42

 

11

 

-

 

 

-

 

53

 

Sales

(24)

(11)

-

-

(1)

-

(36)

 

(14)

 

-

 

 

-

 

(50)

 

Extensions/discoveries

156

5

-

38

35

-

234

 

79

 

-

 

 

-

 

313

 

Production

(111)

(19)

(55)

(171)

(107)

(14)

(477)

 

(66)

 

(66)

 

 

(22)

 

(631)

December 31, 2014

2,108

282

199

1,102

2,132

141

5,964

 

1,092

 

4,233

 

 

534

 

11,823

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2014

330

-

28

-

1,145

-

1,503

 

456

 

-

 

 

-

 

1,959

 

Revisions

19

-

1

-

41

-

61

 

5

 

-

 

 

-

 

66

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

1

-

-

-

-

-

1

 

-

 

-

 

 

-

 

1

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

1

-

-

-

-

-

1

 

-

 

-

 

 

-

 

1

 

Production

(23)

-

(2)

-

(86)

-

(111)

 

(26)

 

-

 

 

-

 

(137)

December 31, 2014

328

-

27

-

1,100

-

1,455

 

435

 

-

 

 

-

 

1,890

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2014

2,436

282

226

1,102

3,232

141

7,419

 

1,527

 

4,233

 

 

534

 

13,713

 

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

   

  

103 


   

Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Synthetic

 

 

 

 

 

Crude Oil and Natural Gas Liquids

 

Bitumen

 

Oil

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

Canada/

 

Canada/

 

 

 

 

 

United

South

 

 

 

 

Australia/

 

 

South

 

South

 

 

 

 

 

States

Amer. (1) 

Europe

Africa

Asia

Oceania

Total

Amer. (2) 

Amer. (3) 

Total

 

 

 

(millions of barrels)

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,489

124

 

268

1,004

1,080

116

4,081

 

543

 

599

 

5,223

 

 

Equity companies

264

 -  

 

28

 -  

1,423

 -  

1,715

 

 -  

 

 -  

 

1,715

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

921

163

 

77

497

682

134

2,474

 

3,017

 

 -  

 

5,491

 

 

Equity companies

84

 -  

 

 -  

 -  

303

 -  

387

 

 -  

 

 -  

 

387

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

2,758

287

 

373

1,501

3,488

250

8,657

 

3,560

 

599

 

12,816

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,469

126

 

249

945

1,663

105

4,557

 

1,810

 

579

 

6,946

 

 

Equity companies

268

 -  

 

27

 -  

1,292

 -  

1,587

 

 -  

 

 -  

 

1,587

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,068

177

 

51

449

638

131

2,514

 

1,820

 

 -  

 

4,334

 

 

Equity companies

77

 -  

 

1

 -  

294

 -  

372

 

 -  

 

 -  

 

372

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

2,882

303

 

328

1,394

3,887

236

9,030

 

3,630

 

579

 

13,239

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,502

111

 

205

894

1,615

112

4,439

 

2,122

 

534

 

7,095

 

 

Equity companies

269

 -  

 

26

 -  

1,188

 -  

1,483

 

 -  

 

 -  

 

1,483

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,234

190

 

42

401

651

99

2,617

 

2,111

 

 -  

 

4,728

 

 

Equity companies

75

 -  

 

1

 -  

331

 -  

407

 

 -  

 

 -  

 

407

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

3,080

301

 

274

1,295

3,785

211

8,946

(4)

4,233

 

534

 

13,713

 

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

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

(3)   Includes total proved reserves attributable to Imperial Oil Limited of 599 million barrels in 2012, 579 million barrels in 2013 and 534 million barrels in 2014, as well as proved developed reserves of 599 million barrels in 2012, 579 million barrels in 2013 and 534 million barrels in 2014, in which there is a 30.4 percent noncontrolling interest.

(4)   See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2014 Form 10-K.

104 


   

Natural Gas and Oil-Equivalent Proved Reserves

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2012

26,254

835

3,586

982

6,471

7,247

45,375

 

17,676

 

 

Revisions

(2,888)

168

168

2

(106)

465

(2,191)

 

(39)

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

7

 

 

Purchases

503

 -  

6

 -  

 -  

 -  

509

 

304

 

 

Sales

(181)

(20)

(140)

(12)

 -  

 -  

(353)

 

(145)

 

 

Extensions/discoveries

4,045

95

184

 -  

59

 -  

4,383

 

1,490

 

 

Production

(1,518)

(153)

(555)

(43)

(579)

(144)

(2,992)

 

(1,124)

 

December 31, 2012

26,215

925

3,249

929

5,845

7,568

44,731

 

18,169

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2012

112

 -  

10,169

 -  

20,566

 -  

30,847

 

7,256

 

 

Revisions

49

 -  

17

 -  

252

 -  

318

 

198

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

16

 

 

Purchases

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Sales

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Extensions/discoveries

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Production

(6)

 -  

(651)

 -  

(1,148)

 -  

(1,805)

 

(475)

 

December 31, 2012

155

 -  

9,535

 -  

19,670

 -  

29,360

 

6,995

 

Total proved reserves at December 31, 2012

26,370

925

12,784

929

25,515

7,568

74,091

 

25,164

 

 

 

 

 

 

 

 

 

 

 

 

 

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2013

26,215

925

3,249

929

5,845

7,568

44,731

 

18,169

 

 

Revisions

79

(56)

61

(22)

364

86

512

 

693

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Purchases

153

522

 -  

 -  

 -  

 -  

675

 

170

 

 

Sales

(106)

(8)

 -  

 -  

 -  

 -  

(114)

 

(43)

 

 

Extensions/discoveries

1,083

2

 -  

 -  

14

 -  

1,099

 

724

 

 

Production

(1,404)

(150)

(500)

(40)

(489)

(139)

(2,722)

 

(1,069)

 

December 31, 2013

26,020

1,235

2,810

867

5,734

7,515

44,181

 

18,644

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2013

155

 -  

9,535

 -  

19,670

 -  

29,360

 

6,995

 

 

Revisions

135

 -  

58

 -  

9

 -  

202

 

77

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Purchases

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Sales

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Extensions/discoveries

1

 -  

8

 -  

 -  

 -  

9

 

2

 

 

Production

(10)

 -  

(717)

 -  

(1,165)

 -  

(1,892)

 

(502)

 

December 31, 2013

281

 -  

8,884

 -  

18,514

 -  

27,679

 

6,572

 

Total proved reserves at December 31, 2013

26,301

1,235

11,694

867

24,248

7,515

71,860

 

25,216

 

 

(See footnotes on next page)

105 


   

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2014

26,020

1,235

2,810

867

5,734

7,515

44,181

 

18,644

 

 

Revisions

49

80

49

(21)

173

(38)

292

 

906

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Purchases

60

 -  

 -  

 -  

 -  

 -  

60

 

63

 

 

Sales

(314)

(48)

 -  

 -  

(3)

 -  

(365)

 

(111)

 

 

Extensions/discoveries

1,518

91

 -  

7

4

 -  

1,620

 

583

 

 

Production

(1,346)

(132)

(476)

(42)

(448)

(201)

(2,645)

 

(1,072)

 

December 31, 2014

25,987

1,226

2,383

811

5,460

7,276

43,143

 

19,013

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2014

281

 -  

8,884

 -  

18,514

 -  

27,679

 

6,572

 

 

Revisions

5

 -  

117

 -  

110

 -  

232

 

105

 

 

Improved recovery

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Purchases

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

1

 

 

Sales

 -  

 -  

 -  

 -  

 -  

 -  

 -  

 

 -  

 

 

Extensions/discoveries

1

 -  

 -  

 -  

 -  

 -  

1

 

1

 

 

Production

(15)

 -  

(583)

 -  

(1,119)

 -  

(1,717)

 

(423)

 

December 31, 2014

272

 -  

8,418

 -  

17,505

 -  

26,195

 

6,256

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2014

26,259

1,226

10,801

811

22,965

7,276

69,338

 

25,269

 

 

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 488 billion cubic feet in 2012, 678 billion cubic feet in 2013 and 627 billion cubic feet in 2014, as well as proved developed reserves of 374 billion cubic feet in 2012, 368 billion cubic feet in 2013 and 300 billion cubic feet in 2014, and in addition, proved undeveloped reserves of 114 billion cubic feet in 2012, 310 billion cubic feet in 2013 and 327 billion cubic feet in 2014, in which there is a 30.4 percent noncontrolling interest.

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

106 


   

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

 

 

 

 

 

equivalent barrels)

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

14,471

670

2,526

814

5,150

1,012

24,643

 

9,330

 

 

 

Equity companies

126

 -  

7,057

 -  

18,431

 -  

25,614

 

5,984

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

11,744

255

723

115

695

6,556

20,088

 

8,839

 

 

 

Equity companies

29

 -  

2,478

 -  

1,239

 -  

3,746

 

1,011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2012

26,370

925

12,784

929

25,515

7,568

74,091

 

25,164

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

14,655

664

2,189

779

5,241

969

24,497

 

11,029

 

 

 

Equity companies

197

 -  

6,852

 -  

17,288

 -  

24,337

 

5,643

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

11,365

571

621

88

493

6,546

19,684

 

7,615

 

 

 

Equity companies

84

 -  

2,032

 -  

1,226

 -  

3,342

 

929

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2013

26,301

1,235

11,694

867

24,248

7,515

71,860

 

25,216

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

14,169

615

1,870

764

5,031

2,179

24,628

 

11,199

 

 

 

Equity companies

194

 -  

6,484

 -  

16,305

 -  

22,983

 

5,314

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

11,818

611

513

47

429

5,097

18,515

 

7,814

 

 

 

Equity companies

78

 -  

1,934

 -  

1,200

 -  

3,212

 

942

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2014

26,259

1,226

10,801

811

22,965

7,276

69,338

 

25,269

 

 

(See footnotes on previous page)

107 


   

Standardized Measure of Discounted Future Cash Flows

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

 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

Standardized Measure of Discounted

 

United

 

South

 

 

 

 

 

 

 

Australia/

 

 

Future Cash Flows

 

States

America (1)

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

250,382

 

293,910

 

66,769

 

160,261

 

192,491

 

104,334

 

1,068,147

 

 

Future production costs

 

109,325

 

101,299

 

17,277

 

33,398

 

42,816

 

26,132

 

330,247

 

 

Future development costs

 

37,504

 

44,518

 

16,505

 

13,363

 

13,083

 

11,435

 

136,408

 

 

Future income tax expenses

 

43,772

 

34,692

 

23,252

 

63,246

 

75,261

 

21,405

 

261,628

 

 

Future net cash flows

 

59,781

 

113,401

 

9,735

 

50,254

 

61,331

 

45,362

 

339,864

 

 

Effect of discounting net cash flows at 10%

 

36,578

 

82,629

 

2,097

 

18,091

 

35,310

 

27,610

 

202,315

 

 

Discounted future net cash flows

 

23,203

 

30,772

 

7,638

 

32,163

 

26,021

 

17,752

 

137,549

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2012

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

36,043

 

 -  

 

93,563

 

 -  

 

348,026

 

 -  

 

477,632

 

 

Future production costs

 

7,040

 

 -  

 

64,988

 

 -  

 

112,980

 

 -  

 

185,008

 

 

Future development costs

 

3,708

 

 -  

 

2,569

 

 -  

 

10,780

 

 -  

 

17,057

 

 

Future income tax expenses

 

 -  

 

 -  

 

9,937

 

 -  

 

78,539

 

 -  

 

88,476

 

 

Future net cash flows

 

25,295

 

 -  

 

16,069

 

 -  

 

145,727

 

 -  

 

187,091

 

 

Effect of discounting net cash flows at 10%

 

14,741

 

 -  

 

8,133

 

 -  

 

76,979

 

 -  

 

99,853

 

 

Discounted future net cash flows

 

10,554

 

 -  

 

7,936

 

 -  

 

68,748

 

 -  

 

87,238

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

33,757

 

30,772

 

15,574

 

32,163

 

94,769

 

17,752

 

224,787

 

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

108 


   

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

Standardized Measure of Discounted

 

United

 

South

 

 

 

 

 

 

 

Australia/

 

 

Future Cash Flows (continued)

 

States

America (1)

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

276,051

 

293,377

 

58,235

 

146,407

 

245,482

 

87,808

 

1,107,360

 

 

Future production costs

 

113,571

 

106,884

 

18,053

 

30,960

 

57,328

 

22,507

 

349,303

 

 

Future development costs

 

40,702

 

43,102

 

15,215

 

14,300

 

10,666

 

10,191

 

134,176

 

 

Future income tax expenses

 

50,144

 

31,901

 

17,186

 

53,766

 

117,989

 

16,953

 

287,939

 

 

Future net cash flows

 

71,634

 

111,490

 

7,781

 

47,381

 

59,499

 

38,157

 

335,942

 

 

Effect of discounting net cash flows at 10%

 

42,336

 

78,700

 

1,278

 

18,406

 

34,878

 

21,266

 

196,864

 

 

Discounted future net cash flows

 

29,298

 

32,790

 

6,503

 

28,975

 

24,621

 

16,891

 

139,078

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

34,957

 

 -  

 

82,539

 

 -  

 

324,666

 

 -  

 

442,162

 

 

Future production costs

 

8,231

 

 -  

 

60,518

 

 -  

 

107,656

 

 -  

 

176,405

 

 

Future development costs

 

3,675

 

 -  

 

2,994

 

 -  

 

8,756

 

 -  

 

15,425

 

 

Future income tax expenses

 

 -  

 

 -  

 

7,237

 

 -  

 

70,887

 

 -  

 

78,124

 

 

Future net cash flows

 

23,051

 

 -  

 

11,790

 

 -  

 

137,367

 

 -  

 

172,208

 

 

Effect of discounting net cash flows at 10%

 

12,994

 

 -  

 

5,549

 

 -  

 

72,798

 

 -  

 

91,341

 

 

Discounted future net cash flows

 

10,057

 

 -  

 

6,241

 

 -  

 

64,569

 

 -  

 

80,867

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

39,355

 

32,790

 

12,744

 

28,975

 

89,190

 

16,891

 

219,945

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

283,767

 

354,223

 

42,882

 

125,125

 

224,885

 

78,365

 

1,109,247

 

 

Future production costs

 

116,929

 

140,368

 

14,358

 

27,917

 

57,562

 

20,467

 

377,601

 

 

Future development costs

 

42,276

 

48,525

 

13,000

 

14,603

 

12,591

 

8,956

 

139,951

 

 

Future income tax expenses

 

49,807

 

36,787

 

10,651

 

44,977

 

102,581

 

15,050

 

259,853

 

 

Future net cash flows

 

74,755

 

128,543

 

4,873

 

37,628

 

52,151

 

33,892

 

331,842

 

 

Effect of discounting net cash flows at 10%

 

44,101

 

87,799

 

(52)

 

13,831

 

30,173

 

17,326

 

193,178

 

 

Discounted future net cash flows

 

30,654

 

40,744

 

4,925

 

23,797

 

21,978

 

16,566

 

138,664

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

31,924

 

 -  

 

71,031

 

 -  

 

286,124

 

 -  

 

389,079

 

 

Future production costs

 

8,895

 

 -  

 

50,826

 

 -  

 

99,193

 

 -  

 

158,914

 

 

Future development costs

 

3,386

 

 -  

 

2,761

 

 -  

 

11,260

 

 -  

 

17,407

 

 

Future income tax expenses

 

 -  

 

 -  

 

6,374

 

 -  

 

59,409

 

 -  

 

65,783

 

 

Future net cash flows

 

19,643

 

 -  

 

11,070

 

 -  

 

116,262

 

 -  

 

146,975

 

 

Effect of discounting net cash flows at 10%

 

10,970

 

 -  

 

5,534

 

 -  

 

61,550

 

 -  

 

78,054

 

 

Discounted future net cash flows

 

8,673

 

 -  

 

5,536

 

 -  

 

54,712

 

 -  

 

68,921

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

39,327

 

40,744

 

10,461

 

23,797

 

76,690

 

16,566

 

207,585

 

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

109 


   

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

 

Consolidated and Equity Interests

 

 

 

 

2012

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2011

 

152,244

 

 

86,560

 

 

238,804

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

7,952

 

 

531

 

 

8,483

 

Changes in value of previous-year reserves due to:

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

production (lifting) costs

 

(51,752)

 

 

(23,022)

 

 

(74,774)

 

 

Development costs incurred during the year

 

24,596

 

 

1,186

 

 

25,782

 

 

Net change in prices, lifting and development costs

 

(31,382)

 

 

5,656

 

 

(25,726)

 

 

Revisions of previous reserves estimates

 

3,876

 

 

7,018

 

 

10,894

 

 

Accretion of discount

 

19,676

 

 

8,846

 

 

28,522

 

Net change in income taxes

 

12,339

 

 

463

 

 

12,802

 

 

 

Total change in the standardized measure during the year

 

(14,695)

 

 

678

 

 

(14,017)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2012

 

137,549

 

 

87,238

 

 

224,787

 

 

Consolidated and Equity Interests

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2012

 

137,549

 

 

87,238

 

 

224,787

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

11,928

 

 

48

 

 

11,976

 

Changes in value of previous-year reserves due to:

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

production (lifting) costs

 

(48,742)

 

 

(23,757)

 

 

(72,499)

 

 

Development costs incurred during the year

 

24,821

 

 

1,389

 

 

26,210

 

 

Net change in prices, lifting and development costs

 

(32,423)

 

 

(5,296)

 

 

(37,719)

 

 

Revisions of previous reserves estimates

 

24,353

 

 

4,960

 

 

29,313

 

 

Accretion of discount

 

20,596

 

 

9,830

 

 

30,426

 

Net change in income taxes

 

996

 

 

6,455

 

 

7,451

 

 

 

Total change in the standardized measure during the year

 

1,529

 

 

(6,371)

 

 

(4,842)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2013

 

139,078

 

 

80,867

 

 

219,945

 

110 


   

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

 

Consolidated and Equity Interests (continued)

 

 

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2013

 

139,078

 

 

80,867

 

 

219,945

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

3,497

 

 

94

 

 

3,591

 

Changes in value of previous-year reserves due to:

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

production (lifting) costs

 

(44,446)

 

 

(18,366)

 

 

(62,812)

 

 

Development costs incurred during the year

 

24,189

 

 

1,453

 

 

25,642

 

 

Net change in prices, lifting and development costs

 

(50,672)

 

 

(13,165)

 

 

(63,837)

 

 

Revisions of previous reserves estimates

 

35,072

 

 

3,298

 

 

38,370

 

 

Accretion of discount

 

20,098

 

 

8,987

 

 

29,085

 

Net change in income taxes

 

11,848

 

 

5,753

 

 

17,601

 

 

 

Total change in the standardized measure during the year

 

(414)

 

 

(11,946)

 

 

(12,360)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2014

 

138,664

 

 

68,921

 

 

207,585

 

111 


OPERATING SUMMARY (unaudited)

  

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

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

 

 

 

 

 

 

 

 

 

 

Net production

(thousands of barrels daily)

 

 

United States

454

 

431

 

418

 

423

 

408

 

 

Canada/South America

301

 

280

 

251

 

252

 

263

 

 

Europe

184

 

190

 

207

 

270

 

335

 

 

Africa

489

 

469

 

487

 

508

 

628

 

 

Asia

624

 

784

 

772

 

808

 

730

 

 

Australia/Oceania

59

 

48

 

50

 

51

 

58

 

Worldwide

2,111

 

2,202

 

2,185

 

2,312

 

2,422

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Net production

(millions of cubic feet daily)

 

 

United States

3,404

 

3,545

 

3,822

 

3,917

 

2,596

 

 

Canada/South America

310

 

354

 

362

 

412

 

569

 

 

Europe

2,816

 

3,251

 

3,220

 

3,448

 

3,836

 

 

Africa

4

 

6

 

17

 

7

 

14

 

 

Asia

4,099

 

4,329

 

4,538

 

5,047

 

4,801

 

 

Australia/Oceania

512

 

351

 

363

 

331

 

332

 

Worldwide

11,145

 

11,836

 

12,322

 

13,162

 

12,148

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1) 

3,969

 

4,175

 

4,239

 

4,506

 

4,447

 

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

(thousands of barrels daily)

 

 

United States

1,809

 

1,819

 

1,816

 

1,784

 

1,753

 

 

Canada

394

 

426

 

435

 

430

 

444

 

 

Europe

1,454

 

1,400

 

1,504

 

1,528

 

1,538

 

 

Asia Pacific

628

 

779

 

998

 

1,180

 

1,249

 

 

Other Non-U.S.

191

 

161

 

261

 

292

 

269

 

Worldwide

4,476

 

4,585

 

5,014

 

5,214

 

5,253

Petroleum product sales (2) 

 

 

 

 

 

 

 

 

 

 

 

United States

2,655

 

2,609

 

2,569

 

2,530

 

2,511

 

 

Canada

496

 

464

 

453

 

455

 

450

 

 

Europe

1,555

 

1,497

 

1,571

 

1,596

 

1,611

 

 

Asia Pacific and other Eastern Hemisphere

1,085

 

1,206

 

1,381

 

1,556

 

1,562

 

 

Latin America

84

 

111

 

200

 

276

 

280

 

Worldwide

5,875

 

5,887

 

6,174

 

6,413

 

6,414

 

 

Gasoline, naphthas

2,452

 

2,418

 

2,489

 

2,541

 

2,611

 

 

Heating oils, kerosene, diesel oils

1,912

 

1,838

 

1,947

 

2,019

 

1,951

 

 

Aviation fuels

423

 

462

 

473

 

492

 

476

 

 

Heavy fuels

390

 

431

 

515

 

588

 

603

 

 

Specialty petroleum products

698

 

738

 

750

 

773

 

773

 

Worldwide

5,875

 

5,887

 

6,174

 

6,413

 

6,414

 

 

 

 

 

 

 

 

 

 

 

 

Chemical prime product sales (3) 

(thousands of metric tons)

 

 

United States

9,528

 

9,679

 

9,381

 

9,250

 

9,815

 

 

Non-U.S.

14,707

 

14,384

 

14,776

 

15,756

 

16,076

 

Worldwide

24,235

 

24,063

 

24,157

 

25,006

 

25,891

 

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

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

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

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

  

 

112 


 

SIGNATURES

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

 

 

 

 

 

EXXON MOBIL CORPORATION

 

 

 

 

By:

/s/    REX W. TILLERSON        

 

 

(Rex W. Tillerson,

Chairman of the Board)

       

Dated February 25, 2015

     

 

 

  

 

 

POWER OF ATTORNEY

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

     

 

 

  

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 25, 2015.

 

 

 

 

 

 

/s/    REX W. TILLERSON

 

(Rex W. Tillerson)

 

Chairman of the Board

(Principal Executive Officer)

 

 

 

/s/    MICHAEL J. BOSKIN

 

(Michael J. Boskin)

 

Director

 

 

 

/s/    PETER BRABECK-LETMATHE

 

(Peter Brabeck-Letmathe)

 

Director

 

 

 

/s/    URSULA M. BURNS

 

(Ursula M. Burns)

 

Director

 

 

 

/s/    LARRY R. FAULKNER

 

(Larry R. Faulkner)

 

Director

  

113 


 

/s/    JAY S. FISHMAN

 

(Jay S. Fishman)

 

Director

 

/s/    HENRIETTA H. FORE

 

(Henrietta H. Fore)

 

 

Director

 

 

 

/s/    KENNETH C. FRAZIER

 

(Kenneth C. Frazier)

 

Director

 

 

 

/s/    WILLIAM W. GEORGE

 

(William W. George)

 

Director

 

 

 

/s/    SAMUEL J. PALMISANO

 

(Samuel J. Palmisano)

 

Director

 

 

 

/s/    STEVEN S REINEMUND

 

(Steven S Reinemund)

 

Director

 

 

 

/s/    WILLIAM C. WELDON

 

(William C. Weldon)

 

Director

 

 

 

/s/    ANDREW P. SWIGER

 

(Andrew P. Swiger)

 

Senior Vice President

(Principal Financial Officer)

 

 

 

/s/    DAVID S. ROSENTHAL

 

(David S. Rosenthal)

 

Vice President and Controller

(Principal Accounting Officer)

  

114 


INDEX TO EXHIBITS

 

  

 

Exhibit

Description

 

 

3(i)

Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).

 

 

3(ii)

By-Laws, as revised to April 27, 2011 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K on April 29, 2011).

 

 

10(iii)(a.1)

2003 Incentive Program, as approved by shareholders May 28, 2003 (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Annual Report on Form 10-K for 2012).*

 

 

10(iii)(a.2)

Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K of November 28, 2012).*

 

 

10(iii)(a.3)

Extended Provisions for Restricted Stock Unit Agreements – Settlement in Shares.*

 

 

10(iii)(a.4)

Standard Provisions for Restricted Stock Unit Agreements – Settlement in Cash (incorporated by reference to Exhibit 10(iii)(a.4) to the Registrant’s Annual Report on Form 10-K for 2013).*

 

 

10(iii)(b.1)

Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual Report on Form 10-K for 2013).*

 

 

10(iii)(b.2)

Earnings Bonus Unit instrument.*

 

 

10(iii)(c.1)

ExxonMobil Supplemental Savings Plan.*

 

 

10(iii)(c.2)

ExxonMobil Supplemental Pension Plan.*

 

 

10(iii)(c.3)

ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual Report on Form 10-K for 2013).*

 

 

10(iii)(d)

ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Annual Report on Form 10-K for 2011).*

 

 

10(iii)(f.1)

2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Annual Report on Form 10-K for 2013).*

 

 

10(iii)(f.2)

Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 10(iii)(f.2) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).*

 

 

10(iii)(f.3)

Form of restricted stock grant letter for non-employee directors.*

 

 

10(iii)(f.4)

Standing resolution for non-employee director cash fees dated October 26, 2011 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).*

 

 

10(iii)(g.3)

1984 Mobil Compensation Management Retention Plan (incorporated by reference to Exhibit 10(iii)(g.3) to the Registrant’s Annual Report on Form 10-K for 2011).*

 

 

12

Computation of ratio of earnings to fixed charges.

 

 

14

Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2013).

 

 

21

Subsidiaries of the registrant.

 

 

23

Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

 

 

31.1

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

 

 

31.2

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

 

 

31.3

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

  

115 


INDEX TO EXHIBITS – (continued)

 

  

Exhibit

Description

 

 

32.1

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.

 

 

32.2

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.

 

 

32.3

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.

 

 

101

Interactive data files.

 

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

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

116