2015

 

 

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, 2015

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 (4,152,756,609 shares outstanding at January 31, 2016)

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, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $83.20 on the New York Stock Exchange composite tape, was in excess of $346 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2016 Annual Meeting of Shareholders (Part III)

 

 

 

 


 

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015

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

      115  

 

 

Index to Exhibits

      117  

 

 

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 2015 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.6 billion, of which $3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to decrease to approximately $5 billion in 2016 and 2017, mainly reflecting lower project activity in Canada. Capital expenditures are expected to account for approximately 30 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 2015. For technology licensed to third parties, revenues totaled approximately $158 million in 2015. 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 73.5 thousand, 75.3 thousand, and 75.0 thousand at years ended 2015, 2014 and 2013, 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 2.1 thousand, 8.4 thousand, and 9.8 thousand at years ended 2015, 2014 and 2013, respectively. The decrease in CORS employees reflects the multi‑year transition of the company‑operated retail network in portions of Europe to a more capital‑efficient Branded Wholesaler model.  

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. Any material decline in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Upstream segment, financial condition and proved reserves. On the other hand, a material increase in oil or natural gas prices could have a material adverse effect on certain of the Company’s operations, especially in the Downstream and Chemical segments.

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 or electric 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 as scheduled 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, including developing technologies to help reduce greenhouse gas emissions.

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 facilities are designed, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of engineering uncertainties, including those associated with wave, wind, and current intensity, marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rain fall events, and earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our robust facility engineering as well as our rigorous disaster preparedness and response and 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 2015

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. 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. When crude oil and natural gas prices are in the range seen in early 2016 for an extended period of time, under the Securities and Exchange Commission’s (SEC) definition of proved reserves, certain quantities of oil and natural gas could temporarily not qualify as proved reserves. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. Otherwise, no major discovery or other favorable or adverse event has occurred since December 31, 2015, 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

1,155

272

-

-

13,353

3,652

 

 

 

Canada/South America (1) 

92

9

4,108

581

552

4,882

 

 

 

Europe

158

34

-

-

1,593

458

 

 

 

Africa

738

162

-

-

750

1,025

 

 

 

Asia

1,586

121

-

-

4,917

2,526

 

 

 

Australia/Oceania

73

34

-

-

1,962

434

 

 

 

 

Total Consolidated

3,802

632

4,108

581

23,127

12,977

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

221

7

-

-

156

254

 

 

 

Europe

25

-

-

-

6,146

1,049

 

 

 

Asia

802

349

-

-

15,233

3,690

 

 

 

 

Total Equity Company

1,048

356

-

-

21,535

4,993

 

 

 

 

Total Developed

4,850

988

4,108

581

44,662

17,970

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,223

396

-

-

6,027

2,624

 

 

 

Canada/South America (1) 

168

6

452

-

575

722

 

 

 

Europe

26

8

-

-

363

95

 

 

 

Africa

225

5

-

-

43

237

 

 

 

Asia

1,239

-

-

-

412

1,308

 

 

 

Australia/Oceania

52

31

-

-

5,079

929

 

 

 

 

Total Consolidated

2,933

446

452

-

12,499

5,915

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

33

6

-

-

64

50

 

 

 

Europe

-

-

-

-

1,757

293

 

 

 

Asia

275

52

-

-

1,228

531

 

 

 

 

Total Equity Company

308

58

-

-

3,049

874

 

 

 

 

Total Undeveloped

3,241

504

452

-

15,548

6,789

Total Proved Reserves

8,091

1,492

4,560

581

60,210

24,759

 

(1)   South America includes proved developed reserves of 0.1 million barrels of crude oil and natural gas liquids and 23 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 anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; 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; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.

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 natural gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the Corporation’s capital spending and also impact our partners’ capacity to fund their share of joint projects.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

B. Technologies Used in Establishing Proved Reserves Additions in 2015

Additions to ExxonMobil’s proved reserves in 2015 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 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 a member currently serves on the SPE Oil and Gas Reserves Committee.

6 


 

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.

 2. Proved Undeveloped Reserves

At year-end 2015, approximately 6.8 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 27 percent of the 24.8 GOEB reported in proved reserves. This compares to the 8.8 GOEB of proved undeveloped reserves reported at the end of 2014. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 2.7 GOEB from proved undeveloped to proved developed reserves by year-end. The largest transfers were related to Kearl Expansion project start-up and drilling activity in the United States. Mainly due to low prices during 2015, the Corporation reclassified approximately 1 GOEB of proved undeveloped reserves, primarily natural gas reserves in the United States, which no longer meet the SEC definition of proved reserves.

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 2015, extensions and purchases primarily related to United States unconventional and Abu Dhabi drilling added approximately 1.7 GOEB of proved undeveloped reserves. Overall, investments of $19.4 billion were made by the Corporation during 2015 to progress the development of reported proved undeveloped reserves, including $17 billion for oil and gas producing activities and an additional $2.4 billion for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 76 percent of the $25.4 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Australia, the United States, Kazakhstan, the Netherlands, Qatar, and Nigeria 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 natural 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 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.

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

(thousands of barrels daily)

Crude oil and natural gas liquids production

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

326

86

 

304

85

 

283

85

 

 

Canada/South America

 

47

8

 

52

9

 

57

10

 

 

Europe

 

173

28

 

151

28

 

157

27

 

 

Africa

 

511

18

 

469

20

 

451

18

 

 

Asia

 

346

29

 

293

26

 

313

30

 

 

Australia/Oceania

 

33

17

 

39

20

 

29

19

 

 

 

Total Consolidated Subsidiaries

 

1,436

186

 

1,308

188

 

1,290

189

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

61

3

 

63

2

 

61

2

 

 

Europe

 

3

-

 

5

-

 

6

-

 

 

Asia

 

241

68

 

236

69

 

373

68

 

 

 

Total Equity Companies

 

305

71

 

304

71

 

440

70

 

 

 

 

 

 

 

 

 

 

 

 

 

Total crude oil and natural gas liquids production

 

1,741

257

 

1,612

259

 

1,730

259

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/South America

 

289

 

 

180

 

 

148

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Synthetic oil production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/South America

 

58

 

 

60

 

 

65

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liquids production

 

2,345

 

 

2,111

 

 

2,202

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

3,116

 

 

3,374

 

 

3,530

 

 

 

Canada/South America (1) 

 

261

 

 

310

 

 

354

 

 

 

Europe

 

1,110

 

 

1,226

 

 

1,294

 

 

 

Africa

 

5

 

 

4

 

 

6

 

 

 

Asia

 

1,080

 

 

1,067

 

 

1,180

 

 

 

Australia/Oceania

 

677

 

 

512

 

 

351

 

 

 

 

Total Consolidated Subsidiaries

 

6,249

 

 

6,493

 

 

6,715

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

31

 

 

30

 

 

15

 

 

 

Europe

 

1,176

 

 

1,590

 

 

1,957

 

 

 

Asia

 

3,059

 

 

3,032

 

 

3,149

 

 

 

 

Total Equity Companies

 

4,266

 

 

4,652

 

 

5,121

 

Total natural gas production available for sale

 

10,515

 

 

11,145

 

 

11,836

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production

 

4,097

 

 

3,969

 

 

4,175

 

(1)   South America includes natural gas production available for sale for 2015, 2014 and 2013 of 21 million, 21 million, and 28 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 2015

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

41.87

 

44.30

 

49.04

 

51.01

 

48.30

 

49.56

 

47.75

 

 

 

NGL, per barrel

 

16.96

 

21.91

 

27.50

 

33.41

 

21.14

 

29.75

 

22.16

 

 

 

Natural gas, per thousand cubic feet

 

1.65

 

1.78

 

6.47

 

1.57

 

2.02

 

5.13

 

2.95

 

 

 

Bitumen, per barrel

 

-

 

25.07

 

-

 

-

 

-

 

-

 

25.07

 

 

 

Synthetic oil, per barrel

 

-

 

48.15

 

-

 

-

 

-

 

-

 

48.15

 

 

Average production costs, per oil-equivalent barrel - total

12.50

 

22.68

 

15.86

 

10.31

 

7.71

 

8.86

 

12.97

 

 

Average production costs, per barrel - bitumen

 

-

 

19.20

 

-

 

-

 

-

 

-

 

19.20

 

 

Average production costs, per barrel - synthetic oil

 

-

 

41.83

 

-

 

-

 

-

 

-

 

41.83

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

46.34

 

-

 

46.05

 

-

 

48.44

 

-

 

47.99

 

 

 

NGL, per barrel

 

15.37

 

-

 

-

 

-

 

32.36

 

-

 

31.75

 

 

 

Natural gas, per thousand cubic feet

 

2.05

 

-

 

6.27

 

-

 

5.83

 

-

 

5.92

 

 

Average production costs, per oil-equivalent barrel - total

22.15

 

-

 

7.75

 

-

 

1.41

 

-

 

3.89

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

42.58

 

44.30

 

48.97

 

51.01

 

48.36

 

49.56

 

47.79

 

 

 

NGL, per barrel

 

16.92

 

21.91

 

27.50

 

33.41

 

28.94

 

29.75

 

24.77

 

 

 

Natural gas, per thousand cubic feet

 

1.65

 

1.78

 

6.37

 

1.57

 

4.84

 

5.13

 

4.16

 

 

 

Bitumen, per barrel

 

-

 

25.07

 

-

 

-

 

-

 

-

 

25.07

 

 

 

Synthetic oil, per barrel

 

-

 

48.15

 

-

 

-

 

-

 

-

 

48.15

 

 

Average production costs, per oil-equivalent barrel - total

13.16

 

22.68

 

13.09

 

10.31

 

3.96

 

8.86

 

10.56

 

 

Average production costs, per barrel - bitumen

 

-

 

19.20

 

-

 

-

 

-

 

-

 

19.20

 

 

Average production costs, per barrel - synthetic oil

 

-

 

41.83

 

-

 

-

 

-

 

-

 

41.83

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2014

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9 


 

 

 

 

 

United

 

Canada/

 

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

S. America

Europe

 

Africa

 

Asia

 

Oceania

 

Total

During 2013

 

(dollars per unit)

 

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

 

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

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

Net Productive Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

-

 

3

 

8

 

 

Canada/South America

 

1

 

3

 

4

 

 

Europe

 

1

 

1

 

-

 

 

Africa

 

1

 

2

 

2

 

 

Asia

 

2

 

-

 

-

 

 

Australia/Oceania

 

1

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

6

 

9

 

14

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

1

 

2

 

1

 

 

Asia

 

-

 

-

 

1

 

 

 

Total Equity Companies

 

1

 

2

 

2

Total productive exploratory wells drilled

 

7

 

11

 

16

 

 

 

 

 

 

 

 

 

 

Net Dry Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

1

 

2

 

2

 

 

Canada/South America

 

-

 

1

 

4

 

 

Europe

 

2

 

1

 

1

 

 

Africa

 

-

 

1

 

-

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

3

 

5

 

7

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

1

 

2

 

1

 

 

Europe

 

1

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

2

 

2

 

1

Total dry exploratory wells drilled

 

5

 

7

 

8

11 


 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

Net Productive Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

692

 

721

 

755

 

 

Canada/South America

 

53

 

178

 

201

 

 

Europe

 

10

 

8

 

13

 

 

Africa

 

23

 

41

 

33

 

 

Asia

 

14

 

19

 

30

 

 

Australia/Oceania

 

4

 

5

 

3

 

 

 

Total Consolidated Subsidiaries

 

796

 

972

 

1,035

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

390

 

340

 

328

 

 

Europe

 

1

 

2

 

2

 

 

Asia

 

2

 

1

 

8

 

 

 

Total Equity Companies

 

393

 

343

 

338

Total productive development wells drilled

 

1,189

 

1,315

 

1,373

 

 

 

 

 

 

 

 

 

 

Net Dry Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

5

 

6

 

5

 

 

Canada/South America

 

-

 

3

 

-

 

 

Europe

 

3

 

1

 

2

 

 

Africa

 

1

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

9

 

10

 

7

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

1

 

1

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

-

 

1

 

1

Total dry development wells drilled

 

9

 

11

 

8

 

 

 

 

 

 

 

 

 

 

 

Total number of net wells drilled

 

1,210

 

1,344

 

1,405

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 2015, the company’s share of net production of synthetic crude oil was 58 thousand barrels per day and share of net acreage was 63 thousand acres in the Athabasca oil sands deposit.

Kearl Operations. Kearl 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 49 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 bitumen extraction and froth treatment trains. 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 and rail. During 2015, average net production at Kearl was 149 thousand barrels per day. The Kearl Expansion project was completed and started up in 2015, adding additional capacity of 110 thousand barrels of bitumen per day.

 

5. Present Activities

A. Wells Drilling

 

 

 

 

Year-End 2015

 

Year-End 2014

 

 

 

 

Gross

 

Net

 

Gross

 

Net

Wells Drilling

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

860

 

379

 

1,120

 

442

 

 

Canada/South America

15

 

10

 

35

 

29

 

 

Europe

14

 

6

 

18

 

8

 

 

Africa

23

 

7

 

33

 

12

 

 

Asia

65

 

18

 

90

 

26

 

 

Australia/Oceania

3

 

1

 

10

 

4

 

 

 

Total Consolidated Subsidiaries

980

 

421

 

1,306

 

521

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

18

 

3

 

31

 

6

 

 

Europe

9

 

3

 

4

 

1

 

 

Asia

1

 

-

 

1

 

-

 

 

 

Total Equity Companies

28

 

6

 

36

 

7

Total gross and net wells drilling

1,008

 

427

 

1,342

 

528

 

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2015 acreage holdings totaled 14.0 million net acres, of which 1.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During the year, 1,063.2 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 and the Bakken oil play in North Dakota and Montana. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia and the Utica Shale of Ohio.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2015 was 1.2 million acres. A total of 3.5 net development wells were completed during the year. The deepwater Hadrian South project and the non-operated Lucius project started up in 2015. ExxonMobil continued development activities on the Heidelberg and Julia Phase 1 projects. Offshore California 1.0 net development well was completed.  

13 


 

Participation in Alaska production and development continued with a total of 20.9 net development wells completed. Development activities continued on the Point Thomson project.

CANADA / SOUTH AMERICA  

Canada

Oil and Gas Operations:  ExxonMobil’s year-end 2015 acreage holdings totaled 6.2 million net acres, of which 1.9 million net acres were offshore. A total of 11.1 net exploration and development wells were completed during the year. Development activities continued on the Hebron project during 2015.  

In Situ Bitumen Operations:  ExxonMobil’s year-end 2015 in situ bitumen acreage holdings totaled 0.7 million net onshore acres. A total of 41.0 net development wells were completed during the year. The Cold Lake Nabiye Expansion project started up in 2015.

Argentina

ExxonMobil’s net acreage totaled 0.9 million onshore acres at year-end 2015, and there were 1.0 net development wells completed during the year.

EUROPE

Germany

A total of 4.8 million net onshore acres were held by ExxonMobil at year-end 2015, with 0.7 net development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2015, of which 1.2 million acres were onshore. A total of 3.5 net exploration and development wells were completed during the year.

Norway

ExxonMobil’s net interest in licenses at year-end 2015 totaled approximately 0.2 million acres, all offshore. A total of 6.8 net exploration and development wells were completed in 2015. The non-operated Aasgard Subsea Compression project started up in 2015.   

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2015 totaled approximately 0.5 million acres, all offshore. A total of 5.1 net development wells were completed during the year.  

AFRICA

Angola

ExxonMobil’s net acreage totaled 0.4 million offshore acres at year-end 2015, with 3.6 net development wells completed during the year. On Block 15, the Kizomba Satellites Phase 2 project started up in 2015. On Block 32, development activities continued on the Kaombo Split Hub project.  

Chad

ExxonMobil’s net year-end 2015 acreage holdings consisted of 46 thousand onshore acres, with 15.6 net development wells completed during the year.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2015, with 2.3 net development wells completed during the year. In 2015, ExxonMobil acquired deepwater acreage in Block EG 06.  

Nigeria

ExxonMobil’s net acreage totaled 1.1 million offshore acres at year-end 2015, with 2.9 net exploration and development wells completed during the year. In 2015, ExxonMobil acquired deepwater acreage in Block OPL 247. The deepwater Erha North Phase 2 project started up, and development drilling continued on the deepwater Usan project in 2015.

14 


 

ASIA

Azerbaijan

At year-end 2015, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.9 net development wells were completed during the year.  

Indonesia

At year-end 2015, ExxonMobil had 0.5 million net acres, 0.4 million net acres offshore and 0.1 million net acres onshore, with 3.2 net development wells completed during the year. In 2015, acreage was relinquished in the North Sumatra and Arun fields. The Banyu Urip onshore central processing facility started up in 2015.  

Iraq

At year-end 2015, ExxonMobil’s onshore acreage was 0.6 million net acres. West Qurna Phase 1 oil field rehabilitation activities continued during 2015 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, after operations were temporarily suspended due to security concerns in the region during 2014, ExxonMobil resumed its seismic program and exploration drilling in 2015, with 1.6 net exploration wells completed during the year.    

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2015. A total of 3.7 net development wells were completed during 2015. 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 2015. During the year, a total of 4.0 net development wells were completed.  

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2015. ExxonMobil participated in 62.2 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 2015.

 

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2015 were 85 thousand acres, all offshore. A total of 1.5 net development wells were completed. The Arkutun-Dagi project started up, and development activities continued on the Odoptu Stage 2 project in 2015.

At year-end 2015, 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 2015.

 

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2015. During the year, a total of 3.6 net development wells were completed. Development activities continued on the Upper Zakum 750 project.

15 


 

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2015 acreage holdings totaled 1.5 million net offshore acres. During the year, a total of 3.1 net exploration and development wells were completed. Construction activities continued on the Gas Conditioning Plant at Longford.

Project construction and commissioning activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2015. 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 2015, with 1.5 net development wells completed during the year. The Papua New Guinea (PNG) LNG integrated development includes gas production and processing facilities in the southern PNG Highlands, onshore and offshore pipelines, and a 6.9 million tonnes per year LNG facility near Port Moresby.

WORLDWIDE EXPLORATION

At year-end 2015, 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 12.6 million net acres were held at year-end 2015 and 4.4 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 43 million barrels of oil and 2,800 billion cubic feet of natural gas for the period from 2016 through 2018. 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 2015

 

Year-End 2014

 

 

 

 

Oil

Gas

 

Oil

Gas

 

 

 

 

Gross

Net

Gross

Net

 

Gross

Net

Gross

Net

Gross and Net Productive Wells

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

20,662

8,334

33,657

20,307

 

18,424

7,939

33,149

20,398

 

 

Canada/South America

5,045

4,741

4,559

1,769

 

5,012

4,659

4,577

1,782

 

 

Europe

1,195

345

644

255

 

1,215

347

642

259

 

 

Africa

1,315

517

20

8

 

1,299

513

19

8

 

 

Asia

818

280

149

87

 

804

267

207

150

 

 

Australia/Oceania

630

138

49

23

 

669

157

43

21

 

 

 

Total Consolidated Subsidiaries

29,665

14,355

39,078

22,449

 

27,423

13,882

38,637

22,618

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

14,555

5,594

4,301

493

 

14,571

5,605

4,365

494

 

 

Europe

13

6

570

180

 

57

20

567

179

 

 

Asia

121

30

125

30

 

110

27

125

30

 

 

 

Total Equity Companies

14,689

5,630

4,996

703

 

14,738

5,652

5,057

703

Total gross and net productive wells

44,354

19,985

44,074

23,152

 

42,161

19,534

43,694

23,321

 

There were 35,909 gross and 30,114 net operated wells at year-end 2015 and 35,446 gross and 29,870 net operated wells at year-end 2014. The number of wells with multiple completions was 1,266 gross in 2015 and 1,219 gross in 2014.

Note: Year-end 2014 consolidated subsidiaries well counts for gross and net wells in the United States were restated in regards to non-operated wells.

17 


 

B. Gross and Net Developed Acreage   

 

 

 

 

Year-End 2015

 

Year-End 2014

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Developed Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

14,827

 

9,327

 

14,777

 

9,367

 

 

Canada/South America (1) 

3,335

 

2,122

 

3,515

 

2,242

 

 

Europe

3,275

 

1,473

 

3,337

 

1,506

 

 

Africa

2,493

 

866

 

2,286

 

815

 

 

Asia

1,934

 

562

 

1,817

 

551

 

 

Australia/Oceania

2,123

 

781

 

2,123

 

758

 

 

 

Total Consolidated Subsidiaries

27,987

 

15,131

 

27,855

 

15,239

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

939

 

209

 

949

 

208

 

 

Europe

4,278

 

1,335

 

4,342

 

1,356

 

 

Asia

628

 

155

 

628

 

156

 

 

 

Total Equity Companies

5,845

 

1,699

 

5,919

 

1,720

Total gross and net developed acreage

33,832

 

16,830

 

33,774

 

16,959

(1)   Includes developed acreage in South America of 213 gross and 109 net thousands of acres for 2015 and 213 gross and 109 net thousands of acres for 2014.

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 2015

 

Year-End 2014

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Undeveloped Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

9,353

 

4,358

 

10,262

 

4,894

 

 

Canada/South America (1) 

19,328

 

10,113

 

16,100

 

12,250

 

 

Europe

10,073

 

5,444

 

10,601

 

5,636

 

 

Africa

10,586

 

5,306

 

22,143

 

15,020

 

 

Asia

6,888

 

3,959

 

17,437

 

13,016

 

 

Australia/Oceania

5,629

 

1,902

 

6,653

 

2,013

 

 

 

Total Consolidated Subsidiaries

61,857

 

31,082

 

83,196

 

52,829

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

259

 

92

 

350

 

118

 

 

Europe

-

 

-

 

-

 

-

 

 

Asia

191,147

 

63,633

 

191,146

 

63,632

 

 

 

Total Equity Companies

191,406

 

63,725

 

191,496

 

63,750

Total gross and net undeveloped acreage

253,263

 

94,807

 

274,692

 

116,579

(1)   Includes undeveloped acreage in South America of 10,634 gross and 4,970 net thousands of acres for 2015 and 9,056 gross and 8,083 net thousands of acres for 2014.

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 exploration and production rights are acquired from mineral interest owners through a lease. Mineral interest owners include the Federal and State governments, as well as private mineral interest owners. Leases typically 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 regarding private property, 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 up to 50 years at the discretion of the government.

Equatorial Guinea

Exploration, development and production activities are governed by production sharing contracts (PSCs) negotiated with the State Ministry of Mines, Industry and Energy. A new PSC was signed in 2015; the initial exploration period is five years for oil and gas, with multi-year extensions available at the discretion of the Ministry and limited relinquishments in the absence of commercial discoveries. The production period for crude oil ranges from 25 to 30 years, while the production period for natural gas ranges from 25 to 50 years.

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 typically 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 (PSCs) negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years, with extensions available as provided by the PSCs and at the discretion of the regional government of Kurdistan. 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 provisions of the respective contract.

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. Due to force majeure events, the development period has been extended beyond its original expiration date by an additional 400 days, with the possibility of further extensions due to ongoing force majeure events.

 

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

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 2015 (1)

 

 

 

 

ExxonMobil

ExxonMobil

 

 

 

 

Share  KBD (2) 

Interest %

United States

 

 

 

 

 

 

Torrance

California

150

 

100

 

 

Joliet

Illinois

236

 

100

 

 

Baton Rouge

Louisiana

503

 

100

 

 

Billings

Montana

60

 

100

 

 

Baytown

Texas

561

 

100

 

 

Beaumont

Texas

345

 

100

 

 

 

 Total United States

 

1,855

 

 

 

 

 

 

 

 

 

 

 

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

239

 

82.9

 

 

Karlsruhe

Germany

78

 

25

 

 

Augusta

Italy

198

 

100

 

 

Trecate

Italy

132

 

74.8

 

 

Rotterdam

Netherlands

191

 

100

 

 

Slagen

Norway

116

 

100

 

 

Fawley

United Kingdom

261

 

100

 

 

 

Total Europe

 

1,655

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

Altona

Australia

78

 

100

 

 

Fujian

China

67

 

25

 

 

Jurong/PAC

Singapore

592

 

100

 

 

Sriracha

Thailand

167

 

66

 

 

 

Total Asia Pacific

 

904

 

 

 

 

 

 

 

 

 

 

 

Middle East

 

 

 

 

 

 

Yanbu

Saudi Arabia

200

 

50

 

 

 

 

 

 

 

 

 

Total Worldwide

 

5,035

 

 

 

 

(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. The listing excludes refineries owned through cost companies in Japan and New Zealand, and the Laffan Refinery in Qatar for which results are reported in the Upstream segment.

(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 2015

 

 

United States

 

 

 

 

Owned/leased

-

 

 

 

Distributors/resellers

9,617

 

 

 

 

Total United States

9,617

 

 

 

 

 

 

 

 

Canada

 

 

 

 

Owned/leased

474

 

 

 

Distributors/resellers

1,281

 

 

 

 

Total Canada

1,755

 

 

 

 

 

 

 

 

Europe

 

 

 

 

Owned/leased

2,438

 

 

 

Distributors/resellers

3,612

 

 

 

 

Total Europe

6,050

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

Owned/leased

645

 

 

 

Distributors/resellers

795

 

 

 

 

Total Asia Pacific

1,440

 

 

 

 

 

 

 

 

Latin America

 

 

 

 

Owned/leased

9

 

 

 

Distributors/resellers

745

 

 

 

 

Total Latin America

754

 

 

 

 

 

 

 

 

Middle East/Africa

 

 

 

 

Owned/leased

372

 

 

 

Distributors/resellers

263

 

 

 

 

Total Middle East/Africa

635

 

 

 

 

 

 

 

 

Worldwide

 

 

 

 

Owned/leased

3,938

 

 

 

Distributors/resellers

16,313

 

 

 

 

Total Worldwide

20,251

 

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 2015 (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

 

0.7

 

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

 

1.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

 

 

 

 

 

 

Antwerp

Belgium

-

 

0.4

 

-

 

-

 

100

 

 

Fife

United Kingdom

0.4

 

-

 

-

 

-

 

50

 

 

Gravenchon

France

0.4

 

0.4

 

0.3

 

-

 

100

 

 

Meerhout

Belgium

-

 

0.5

 

-

 

-

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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. The listing excludes cost company capacity in Japan.

25 


 

Item 3.       Legal Proceedings

As reported in the Corporation’s Form 10-Q for the third quarter of 2015, following ExxonMobil Oil Corporation’s (EMOC) self-reporting of an air emission event at the ExxonMobil Beaumont Chemical Plant, the Texas Commission on Environmental Quality (TCEQ) notified EMOC on September 17, 2015, that it was seeking a penalty of $150,000 for exceeding provisions of the Texas Administrative Code and the Texas Health and Safety Code. On December 15, 2015, the TCEQ agreed with EMOC on the duration of the event, and the parties agreed to an administrative penalty of $50,000, of which $25,000 was paid to the TCEQ on January 7, 2016. The balance will be paid for a Supplemental Environmental Project upon endorsement by the TCEQ.

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: 63

Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004, and was President through December 31, 2015. He became Chairman of the Board and Chief Executive Officer on January 1, 2006, positions he still holds as of the filing date.

 

Darren W. Woods

President

 

 

 

 

Held current title since:

January 1, 2016

Age: 51

Mr. Darren W. Woods 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 was Senior Vice President of Exxon Mobil Corporation June 1, 2014 – December 31, 2015. He became a Director and President of Exxon Mobil Corporation on January 1, 2016, positions he still holds as of this filing date.

 

Mark W. Albers

Senior Vice President

 

 

 

 

Held current title since:

April 1, 2007

Age: 59

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: 62

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: 59

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: 52

Mr. Jack P. Williams, Jr. 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.

 

S. Jack Balagia

Vice President and General Counsel

 

 

 

 

Held current title since:

March 1, 2010

Age: 64

Mr. S. Jack Balagia 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: 53

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: 54

Mr. Randy J. Cleveland 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: 62

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.

 

Bradley W. Corson

Vice President

 

 

 

Held current title since:

March 1, 2015

Age: 54

Mr. Bradley W. Corson was Regional Vice President, Europe/Caspian for ExxonMobil Production Company May 1, 2009 – April 30, 2014. He was Vice President, ExxonMobil Upstream Ventures May 1, 2014 – February 28, 2015. He became President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation on March 1, 2015, positions he still holds as of this filing date.

 

Neil W. Duffin

President, ExxonMobil Development Company

 

 

 

Held current title since:

April 13, 2007

Age: 59

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: 58

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: 58

Mr. Stephen M. Greenlee became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.

 

Alan J. Kelly

Vice President

 

 

 

 

Held current title since:

December 1, 2007

Age: 58

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.

 

  

28 


 

David S. Rosenthal

Vice President and Controller

 

 

 

Held current title since:

October 1, 2008 (Vice President)

September 1, 2014 (Controller)

Age: 59

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: 59

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: 54

Mr. James M. Spellings, Jr. 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: 61

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: 59

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: 55

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, 2015

 

 

 

 

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 2015

2,251,296

79.78

2,251,296

 

November 2015

3,845,713

81.66

3,845,713

 

December 2015

3,292,255

79.01

3,292,255

 

 

Total

9,389,264

80.28

9,389,264

(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, 2016, the Corporation stated it will continue to acquire shares to offset dilution in conjunction with benefit plans and programs, but does not plan on making purchases to reduce shares outstanding.

Item 6.       Selected Financial Data

 

 

 

Years Ended December 31,

 

 

2015

 

2014

 

2013

 

2012

 

2011

 

 

(millions of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue (1) 

 

259,488

 

394,105

 

420,836

 

451,509

 

467,029

          (1) Sales-based taxes included

 

22,678

 

29,342

 

30,589

 

32,409

 

33,503

Net income attributable to ExxonMobil

 

16,150

 

32,520

 

32,580

 

44,880

 

41,060

Earnings per common share

 

3.85

 

7.60

 

7.37

 

9.70

 

8.43

Earnings per common share - assuming dilution

 

3.85

 

7.60

 

7.37

 

9.70

 

8.42

Cash dividends per common share

 

2.88

 

2.70

 

2.46

 

2.18

 

1.85

Total assets

 

336,758

 

349,493

 

346,808

 

333,795

 

331,052

Long-term debt

 

19,925

 

11,653

 

6,891

 

7,928

 

9,322

 

 

 

 

 

 

 

 

 

 

 

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 24, 2016, 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, 2015. 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, 2015.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2015, 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 2016 annual meeting of shareholders (the “2016 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 2016 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 2016 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

31,090,370

(1)

 

-

 

100,899,852

(2)(3)

 

 

 

 

 

 

 

 

 

Equity compensation plans not approved by security holders

-

 

 

-

 

-

 

 

 

 

 

 

 

 

 

 

 

Total

31,090,370

 

 

-

 

100,899,852

 

 

(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 100,324,152 shares available for award under the 2003 Incentive Program and 575,700 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 2016 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 2016 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

40

 

 

Overview

40

 

 

Business Environment and Risk Assessment

41

 

 

Review of 2015 and 2014 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

61

 

 

Report of Independent Registered Public Accounting Firm

62

 

 

Consolidated Financial Statements

 

 

 

Statement of Income

63

 

 

Statement of Comprehensive Income

64

 

 

Balance Sheet

65

 

 

Statement of Cash Flows

66

 

 

Statement of Changes in Equity

67

 

 

Notes to Consolidated Financial Statements

 

 

 

  1. Summary of Accounting Policies

68

 

 

  2. Accounting Changes

71

 

 

  3. Miscellaneous Financial Information

71

 

 

  4. Other Comprehensive Income Information

72

 

 

  5. Cash Flow Information

73

 

 

  6. Additional Working Capital Information

73

 

 

  7. Equity Company Information

74

 

 

  8. Investments, Advances and Long-Term Receivables

75

 

 

  9. Property, Plant and Equipment and Asset Retirement Obligations

76

 

 

10. Accounting for Suspended Exploratory Well Costs

77

 

 

11. Leased Facilities

79

 

 

12. Earnings Per Share

79

 

 

13. Financial Instruments and Derivatives

80

 

 

14. Long-Term Debt

81

 

 

15. Incentive Program

82

 

 

16. Litigation and Other Contingencies

83

 

 

17. Pension and Other Postretirement Benefits

85

 

 

18. Disclosures about Segments and Related Information

93

 

 

19. Income, Sales-Based and Other Taxes

96

 

 

Supplemental Information on Oil and Gas Exploration and Production Activities

99

 

 

Operating Summary

114

 

  

34 


BUSINESS PROFILE

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

Return on

 

 

Capital and

 

 

 

 

Earnings After

 

Average Capital

 

Average Capital

 

 

Exploration

 

 

 

 

Income Taxes

 

Employed

 

Employed

 

 

Expenditures

Financial

 

2015

 

2014

 

2015

 

2014

 

2015

 

2014

 

 

2015

 

2014

 

 

 

 

(millions of dollars)

 

(percent)

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

(1,079)

 

5,197

 

64,086

 

62,403

 

(1.7)

 

8.3

 

 

7,822

 

9,401

 

Non-U.S.

 

8,180

 

22,351

 

105,868

 

102,562

 

7.7

 

21.8

 

 

17,585

 

23,326

 

 

Total

 

7,101

 

27,548

 

169,954

 

164,965

 

4.2

 

16.7

 

 

25,407

 

32,727

Downstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

1,901

 

1,618

 

7,497

 

6,070

 

25.4

 

26.7

 

 

1,039

 

1,310

 

Non-U.S.

 

4,656

 

1,427

 

15,756

 

17,907

 

29.6

 

8.0

 

 

1,574

 

1,724

 

 

Total

 

6,557

 

3,045

 

23,253

 

23,977

 

28.2

 

12.7

 

 

2,613

 

3,034

Chemical

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

2,386

 

2,804

 

7,696

 

6,121

 

31.0

 

45.8

 

 

1,945

 

1,690

 

Non-U.S.

 

2,032

 

1,511

 

16,054

 

16,076

 

12.7

 

9.4

 

 

898

 

1,051

 

 

Total

 

4,418

 

4,315

 

23,750

 

22,197

 

18.6

 

19.4

 

 

2,843

 

2,741

Corporate and financing

 

(1,926)

 

(2,388)

 

(8,202)

 

(8,029)

 

-

 

-

 

 

188

 

35

 

 

Total

 

16,150

 

32,520

 

208,755

 

203,110

 

7.9

 

16.2

 

 

31,051

 

38,537

 

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



 

Operating

2015

 

2014

 

 

 

 

2015

 

2014

 

 

(thousands of barrels daily)

 

 

 

(thousands of barrels daily)

Net liquids production

 

 

 

 

Refinery throughput

 

 

 

 

United States

476

 

454

 

 

United States

1,709

 

1,809

 

Non-U.S.

1,869

 

1,657

 

 

Non-U.S.

2,723

 

2,667

 

 

Total

2,345

 

2,111

 

 

 

Total

4,432

 

4,476

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

 

 

(thousands of barrels daily)

Natural gas production available for sale

 

 

 

 

Petroleum product sales (2) 

 

 

 

 

United States

3,147

 

3,404

 

 

United States

2,521

 

2,655

 

Non-U.S.

7,368

 

7,741

 

 

Non-U.S.

3,233

 

3,220

 

 

Total

10,515

 

11,145

 

 

 

Total

5,754

 

5,875

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

 

 

(thousands of metric tons)

Oil-equivalent production (1) 

4,097

 

3,969

 

Chemical prime product sales (2)(3)

 

 

 

 

 

 

 

 

 

 

 

United States

9,664

 

9,528

 

 

 

 

 

 

 

 

Non-U.S.

15,049

 

14,707

 

 

 

 

 

 

 

 

 

Total

24,713

 

24,235

 

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

(2)     Petroleum product and chemical prime 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.

  

35 


FINANCIAL SUMMARY

 

 

  

 

 

 

 

2015

 

2014

 

2013

 

2012

 

2011

 

 

(millions of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue (1) 

 

259,488

 

394,105

 

420,836

 

451,509

 

467,029

Earnings

 

 

 

 

 

 

 

 

 

 

 

Upstream

 

7,101

 

27,548

 

26,841

 

29,895

 

34,439

 

Downstream

 

6,557

 

3,045

 

3,449

 

13,190

 

4,459

 

Chemical

 

4,418

 

4,315

 

3,828

 

3,898

 

4,383

 

Corporate and financing

 

(1,926)

 

(2,388)

 

(1,538)

 

(2,103)

 

(2,221)

 

Net income attributable to ExxonMobil

 

16,150

 

32,520

 

32,580

 

44,880

 

41,060

Earnings per common share

 

3.85

 

7.60

 

7.37

 

9.70

 

8.43

Earnings per common share – assuming dilution

 

3.85

 

7.60

 

7.37

 

9.70

 

8.42

Cash dividends per common share

 

2.88

 

2.70

 

2.46

 

2.18

 

1.85

 

 

 

 

 

 

 

 

 

 

 

 

Earnings to average ExxonMobil share of equity (percent)

 

9.4

 

18.7

 

19.2

 

28.0

 

27.3

 

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

(11,353)

 

(11,723)

 

(12,416)

 

321

 

(4,542)

Ratio of current assets to current liabilities (times)

 

0.79

 

0.82

 

0.83

 

1.01

 

0.94

 

 

 

 

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

27,475

 

34,256

 

37,741

 

35,179

 

33,638

Property, plant and equipment, less allowances

 

251,605

 

252,668

 

243,650

 

226,949

 

214,664

Total assets

 

336,758

 

349,493

 

346,808

 

333,795

 

331,052

 

 

 

 

 

 

 

 

 

 

 

 

Exploration expenses, including dry holes

 

1,523

 

1,669

 

1,976

 

1,840

 

2,081

Research and development costs

 

1,008

 

971

 

1,044

 

1,042

 

1,044

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

19,925

 

11,653

 

6,891

 

7,928

 

9,322

Total debt

 

38,687

 

29,121

 

22,699

 

11,581

 

17,033

Fixed-charge coverage ratio (times)

 

17.6

 

46.9

 

55.7

 

62.4

 

53.4

Debt to capital (percent)

 

18.0

 

13.9

 

11.2

 

6.3

 

9.6

Net debt to capital (percent) (2) 

 

16.5

 

11.9

 

9.1

 

1.2

 

2.6

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil share of equity at year-end

 

170,811

 

174,399

 

174,003

 

165,863

 

154,396

ExxonMobil share of equity per common share

 

41.10

 

41.51

 

40.14

 

36.84

 

32.61

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

 

 

outstanding (millions)

 

4,196

 

4,282

 

4,419

 

4,628

 

4,870

 

 

 

 

 

 

 

 

 

 

 

 

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

 

73.5

 

75.3

 

75.0

 

76.9

 

82.1

 

 

 

 

 

 

 

 

 

 

 

 

CORS employees not included above (thousands) (4) 

 

2.1

 

8.4

 

9.8

 

11.1

 

17.0

 

(1)   Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014, $30,589 million for 2013, $32,409 million for 2012 and $33,503 million for 2011.

(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

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

30,344

 

45,116

 

44,914

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

 

 

 

 

 

 

 

and sales and returns of investments

 

2,389

 

4,035

 

2,707

 

Cash flow from operations and asset sales

 

32,733

 

49,151

 

47,621

 

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

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

Business uses: asset and liability perspective

 

 

 

 

 

 

Total assets

 

336,758

 

349,493

 

346,808

Less liabilities and noncontrolling interests share of assets and liabilities

 

 

 

 

 

 

 

Total current liabilities excluding notes and loans payable

 

(35,214)

 

(47,165)

 

(55,916)

 

Total long-term liabilities excluding long-term debt

 

(86,047)

 

(92,143)

 

(87,698)

 

Noncontrolling interests share of assets and liabilities

 

(8,286)

 

(9,099)

 

(8,935)

Add ExxonMobil share of debt-financed equity company net assets

 

4,447

 

4,766

 

6,109

 

Total capital employed

 

211,658

 

205,852

 

200,368

 

 

 

 

 

 

 

 

Total corporate sources: debt and equity perspective

 

 

 

 

 

 

Notes and loans payable

 

18,762

 

17,468

 

15,808

Long-term debt

 

19,925

 

11,653

 

6,891

ExxonMobil share of equity

 

170,811

 

174,399

 

174,003

Less noncontrolling interests share of total debt

 

(2,287)

 

(2,434)

 

(2,443)

Add ExxonMobil share of equity company debt

 

4,447

 

4,766

 

6,109

 

Total capital employed

 

211,658

 

205,852

 

200,368

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

 

2015

 

2014

 

2013

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income attributable to ExxonMobil

 

16,150

 

32,520

 

32,580

Financing costs (after tax)

 

 

 

 

 

 

 

Gross third-party debt

 

(362)

 

(140)

 

(163)

 

ExxonMobil share of equity companies

 

(170)

 

(256)

 

(239)

 

All other financing costs – net

 

88

 

(68)

 

83

 

 

Total financing costs

 

(444)

 

(464)

 

(319)

 

 

 

Earnings excluding financing costs

 

16,594

 

32,984

 

32,899

 

 

 

 

 

 

 

 

 

 

Average capital employed

 

208,755

 

203,110

 

191,575

 

 

 

 

 

 

 

 

 

 

Return on average capital employed – corporate total

 

7.9%

 

16.2%

 

17.2%

38 


QUARTERLY INFORMATION

 

 

  

 

 

 

2015

 

2014

 

 

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)

 

natural gas liquids,

2,277

2,291

2,331

2,481

2,345

 

2,148

2,048

2,065

2,182

2,111

 

synthetic oil and bitumen

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

4,546

4,330

4,457

4,395

4,432

 

4,509

4,454

4,591

4,349

4,476

Petroleum product sales (1) 

5,814

5,737

5,788

5,679

5,754

 

5,817

5,841

5,999

5,845

5,875

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production

(millions of cubic feet daily)

 

available for sale

11,828

10,128

9,524

10,603

10,515

 

12,016

10,750

10,595

11,234

11,145

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (2) 

4,248

3,979

3,918

4,248

4,097

 

4,151

3,840

3,831

4,054

3,969

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of metric tons)

Chemical prime product sales (1) (3)

6,069

6,078

6,082

6,484

24,713

 

6,128

6,139

6,249

5,719

24,235

 

 

 

 

 

 

 

 

 

 

 

 

 

Summarized financial data

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating

(millions of dollars)

 

revenue (4) 

64,758

71,360

65,679

57,691

259,488

 

101,312

105,719

103,206

83,868

394,105

Gross profit (5) 

19,030

20,362

20,247

16,211

75,850

 

29,166

28,746

28,825

23,240

109,977

Net income attributable to

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil

4,940

4,190

4,240

2,780

16,150

 

9,100

8,780

8,070

6,570

32,520

 

 

 

 

 

 

 

 

 

 

 

 

 

Per share data

(dollars per share)

Earnings per common share (6) 

1.17

1.00

1.01

0.67

3.85

 

2.10

2.05

1.89

1.56

7.60

Earnings per common share

 

 

 

 

 

 

 

 

 

 

 

 

– assuming dilution (6) 

1.17

1.00

1.01

0.67

3.85

 

2.10

2.05

1.89

1.56

7.60

Dividends per common share

0.69

0.73

0.73

0.73

2.88

 

0.63

0.69

0.69

0.69

2.70

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock prices

 

 

 

 

 

 

 

 

 

 

 

 

High

93.45

90.09

83.53

87.44

93.45

 

101.22

104.61

104.76

97.20

104.76

 

Low

82.68

82.80

66.55

73.03

66.55

 

89.25

96.24

93.62

86.19

86.19

 

(1)   Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.

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

(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.

(4)   Includes amounts for sales-based taxes.

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

(6)   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 419,510 registered shareholders of ExxonMobil common stock at December 31, 2015. At January 31, 2016, the registered shareholders of ExxonMobil common stock numbered 418,587.

On January 27, 2016, the Corporation declared a $0.73 dividend per common share, payable March 10, 2016.

  

 

39 


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

 

 

  

FUNCTIONAL EARNINGS

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars, except per share amounts)

Earnings (U.S. GAAP)

 

 

 

 

 

 

Upstream

 

 

 

 

 

 

 

United States

 

(1,079)

 

5,197

 

4,191

 

Non-U.S.

 

8,180

 

22,351

 

22,650

Downstream

 

 

 

 

 

 

 

United States

 

1,901

 

1,618

 

2,199

 

Non-U.S.

 

4,656

 

1,427

 

1,250

Chemical

 

 

 

 

 

 

 

United States

 

2,386

 

2,804

 

2,755

 

Non-U.S.

 

2,032

 

1,511

 

1,073

Corporate and financing

 

(1,926)

 

(2,388)

 

(1,538)

 

 

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

 

16,150

 

32,520

 

32,580

 

 

 

 

 

 

 

 

 

Earnings per common share

 

3.85

 

7.60

 

7.37

Earnings per common share – assuming dilution

 

3.85

 

7.60

 

7.37

 

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.



FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future financial and operating 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 and resulting price impacts; the outcome of commercial negotiations; the impact of fiscal and commercial terms; 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. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, reduces the Corporation’s risk from changes in commodity prices. 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.

40 


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

 

 

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 1.8 billion more than in 2014. 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 25 percent from 2014 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 30 percent from 2014 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 65 percent from 2014 to 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. Today, coal‑fired generation provides about 40 percent of the world’s electricity, but by 2040 its share is likely to decline to about 30 percent, in part as a result of policies to improve air quality and reduce greenhouse gas emissions and the risks of climate change. From 2014 to 2040, the amount of electricity generated using natural gas, nuclear power, and renewables are all likely to double. By 2040, coal, natural gas and renewables are projected to be generating approximately the same share of electricity worldwide, although significant differences will exist across regions reflecting a wide range of factors including the cost and availability of energy types.

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 projected to grow to approximately 112 million barrels of oil‑equivalent per day, an increase of about 20 percent from 2014. 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 it is expected to be the fastest-growing major fuel source from 2014 to 2040, meeting about 40 percent of global energy demand growth. Global natural gas demand is expected to rise about 50 percent from 2014 to 2040, with about 45 percent 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. In total, about 60 percent of the growth in natural gas supplies is expected to be from unconventional sources. However, we expect conventionally-produced natural gas to remain the cornerstone of supply, meeting about two‑thirds of global demand in 2040. The worldwide liquefied natural gas (LNG) market is expected to almost triple by 2040, with much of this supply expected to meet rising demand in Asia Pacific.

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 about 20 percent. Nuclear power is projected to grow significantly, as many nations are likely to 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 rapidly, growing close to 250 percent from 2014 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 oil and natural

41 


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

 

 

gas supply requirements worldwide over the period 2015‑2040 will be about $25 trillion (measured in 2014 dollars) or approximately $1 trillion per year on average.

International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. For many years, the Corporation has taken into account policies established to reduce energy‑related greenhouse gas emissions in its long-term Outlook for Energy, which is used as a foundation for assessing the business environment and business strategies and investments. The climate accord reached at the recent Conference of the Parties (COP 21) in Paris set many new goals, and while many related policies are still emerging, the Outlook for Energy continues to anticipate that such policies will increase the cost of carbon dioxide emissions over time. For purposes of the Outlook for Energy, we continue to assume that governments will enact policies that impose rising costs on energy‑related CO2 emissions, which we assume will reach an implied cost in OECD nations of about $80 per tonne in 2040. China and other leading non‑OECD nations are expected to trail OECD policy initiatives. Nevertheless, as people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. Thus, all practical and economically viable energy sources, both conventional and unconventional, will be needed to continue meeting global energy needs – because of the scale of worldwide energy demand.

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 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 anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; 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; changes in the amount and timing of capital investments that may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.

The upstream industry environment has been challenged throughout 2015 with abundant crude oil supply causing crude oil prices to decrease to levels not seen since 2004, while natural gas prices remained depressed. However, current market conditions are not necessarily indicative of future conditions. The markets for crude oil and natural gas have a history of significant price volatility. 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. On the supply side, prices may be significantly impacted by political events, the actions of OPEC and other large government resource owners, and other factors. 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 exhibit strong performance over the long term. This is the outcome of disciplined investment, cost management, asset enhancement programs, and application of advanced technologies.

 

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.

42 


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

 

 

ExxonMobil’s fundamental Downstream business strategies competitively position the company 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 and differentiated products and services to customers.

ExxonMobil’s operating results, as noted in Item 2. Properties, reflect 23 refineries, located in 14 countries, with distillation capacity of 5 million barrels per day and lubricant basestock manufacturing capacity of 136 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 improved in 2015. Growth in global demand, stimulated by lower prices for crude oil and transportation fuels, resulted in higher refinery utilization and margins, particularly in Europe and Asia Pacific. Refineries in North America continue to benefit from lower raw material and energy costs due to the abundant supply of crude oil and natural gas. In the near term, we see variability in refining margins, with some regions seeing weaker margins as new capacity additions are expected to outpace growth in global demand for our products, which can also be affected by global economic conditions and regulatory changes.

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

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 Downstream business

In the retail fuels marketing business, competition has caused inflation‑adjusted margins to decline. In 2015, ExxonMobil expanded its branded retail site network 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 Wholesaler model. 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, despite increasing competition.

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. In 2015, the company divested its 50 percent share of Chalmette Refining, LLC, and reached an agreement for the sale of the refinery in Torrance, California, with change-in-control expected by mid-2016. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. In 2015, construction continued on a new delayed coker unit at the refinery in Antwerp, Belgium, to upgrade low‑value bunker fuel into higher value diesel products. Funding was approved for the construction of a proprietary hydrocracker at the refinery in Rotterdam, Netherlands, to produce higher value ultra‑low sulfur diesel and Group II basestocks. The company completed an expansion of lubricant basestock capacity at the refinery in Baytown, Texas. Finished lubricant plant expansions in China and Finland were completed, and an expansion in Singapore is underway to support demand growth for finished lubricants and greases in key markets.

 

Chemical

Worldwide petrochemical demand continued to improve in 2015, 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. Specialty product margins improved in 2015, but continued to be impacted by 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 2015, we neared completion of the specialty elastomers project at our joint venture facility in Al-Jubail, Saudi Arabia. Construction continued on 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 to meet rapidly growing demand for premium polymers. Construction of new halobutyl rubber and hydrocarbon resin units also progressed in Singapore to further extend our specialty product capacity in Asia Pacific.

43 


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

 

 

REVIEW OF 2015 AND 2014 RESULTS

 

 

 

 

 

2015

 

2014

 

2013

 

 

(millions of dollars)

Earnings (U.S. GAAP)

 

 

 

 

 

 

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

 

16,150

 

32,520

 

32,580



 

Upstream

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

United States

 

(1,079)

 

5,197

 

4,191

 

Non-U.S.

 

8,180

 

22,351

 

22,650

 

 

Total

 

7,101

 

27,548

 

26,841

 

2015

Upstream earnings were $7,101 million, down $20,447 million from 2014. Lower realizations decreased earnings by $18.8 billion. Favorable volume and mix effects increased earnings by $810 million, including contributions from new developments. All other items decreased earnings by $2.4 billion, primarily due to lower asset management gains and approximately $500 million of lower favorable one‑time tax effects, partly offset by lower expenses of about $230 million.  On an oil‑equivalent basis, production of 4.1 million barrels per day was up 3.2 percent compared to 2014. Liquids production of 2.3 million barrels per day increased 234,000 barrels per day, with project ramp‑up and entitlement effects partly offset by field decline. Natural gas production of 10.5 billion cubic feet per day decreased 630 million cubic feet per day from 2014 as regulatory restrictions in the Netherlands and field decline were partly offset by project ramp‑up, work programs and entitlement effects.  U.S. Upstream earnings declined $6,276 million from 2014 to a loss of $1,079 million in 2015. Earnings outside the U.S. were $8,180 million, down $14,171 million from the prior year.

 

2014

Upstream earnings were $27,548 million, up $707 million from 2013. Lower prices decreased earnings by $2 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 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.

  

44 


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

 

 

Upstream Additional Information

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

 

 

 

(thousands of barrels daily)

Volumes Reconciliation (Oil-equivalent production)(1) 

 

 

 

 

 

Prior year

 

 

 

3,969

 

4,175

 

Entitlements - Net Interest

 

 

 

(14)

 

(4)

 

Entitlements - Price / Spend / Other

 

 

 

168

 

(43)

 

Quotas

 

 

 

-

 

-

 

Divestments

 

 

 

(25)

 

(31)

 

United Arab Emirates Onshore Concession Expiry

 

 

 

(6)

 

(135)

 

Growth / Other

 

 

 

5

 

7

Current Year

 

 

 

4,097

 

3,969

 

 

 

 

 

 

 

 

(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

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

Downstream

 

 

 

 

 

 

 

United States

 

1,901

 

1,618

 

2,199

 

Non-U.S.

 

4,656

 

1,427

 

1,250

 

 

Total

 

6,557

 

3,045

 

3,449

 

2015

Downstream earnings of $6,557 million increased $3,512 million from 2014. Stronger margins increased earnings by $4.1 billion, while volume and mix effects decreased earnings by $200 million. All other items decreased earnings by $420 million, reflecting nearly $560 million in higher maintenance expense and about $280 million in unfavorable inventory impacts, partly offset by favorable foreign exchange effects. Petroleum product sales of 5.8 million barrels per day were 121,000 barrels per day lower than 2014.  U.S. Downstream earnings were $1,901 million, an increase of $283 million from 2014. Non‑U.S. Downstream earnings were $4,656 million, up $3,229 million from the prior year.

 

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.

  

 

Chemical

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

Chemical

 

 

 

 

 

 

 

United States

 

2,386

 

2,804

 

2,755

 

Non-U.S.

 

2,032

 

1,511

 

1,073

 

 

Total

 

4,418

 

4,315

 

3,828

 

2015

Chemical earnings of $4,418 million increased $103 million from 2014. Stronger margins increased earnings by $590 million. Favorable volume and mix effects increased earnings by $220 million. All other items decreased earnings by $710 million, reflecting about $680 million in unfavorable foreign exchange effects and $220 million in negative tax and inventory impacts, partly offset by asset management gains. Prime product sales of 24.7 million metric tons were up 478,000 metric tons from 2014.  U.S. Chemical earnings were $2,386 million, down $418 million from 2014. Non‑U.S. Chemical earnings were $2,032 million, $521 million higher than the prior year.

 

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 metric 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.

  

46 


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

 

 

Corporate and Financing

 

 

 

 

2015

 

2014

 

2013

 

 

(millions of dollars)

 

 

 

 

 

 

 

Corporate and financing

 

(1,926)

 

(2,388)

 

(1,538)

 

2015

Corporate and financing expenses were $1,926 million in 2015 compared to $2,388 million in 2014, with the decrease due mainly to net favorable tax‑related items.

 

2014

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

  

47 


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

 

 

LIQUIDITY AND CAPITAL RESOURCES

 

 

 

 

 

 

 

 

 

 

 

Sources and Uses of Cash

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

Net cash provided by/(used in)

 

 

 

 

 

 

 

Operating activities

 

30,344

 

45,116

 

44,914

 

Investing activities

 

(23,824)

 

(26,975)

 

(34,201)

 

Financing activities

 

(7,037)

 

(17,888)

 

(15,476)

Effect of exchange rate changes

 

(394)

 

(281)

 

(175)

Increase/(decrease) in cash and cash equivalents

 

(911)

 

(28)

 

(4,938)

 

 

 

 

 

 

 

 

 

 

 

(December 31)

Cash and cash equivalents

 

3,705

 

4,616

 

4,644

Cash and cash equivalents - restricted

 

-

 

42

 

269

Total cash and cash equivalents

 

3,705

 

4,658

 

4,913

 

Total cash and cash equivalents were $3.7 billion at the end of 2015, $1.0 billion lower than the prior year. The major sources of funds in 2015 were net income including noncontrolling interests of $16.6 billion, the adjustment for the noncash provision of $18.0 billion for depreciation and depletion, and a net debt increase of $9.3 billion. The major uses of funds included spending for additions to property, plant and equipment of $26.5 billion, the purchase of shares of ExxonMobil stock of $4.0 billion, dividends to shareholders of $12.1 billion and a change in working capital, excluding cash and debt, of $3.1 billion.

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. 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, 2015, the Corporation had unused committed short-term lines of credit of $6.0 billion and unused committed long-term lines of credit of $0.4 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. On average over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. The Corporation anticipates several projects will come online over the next few years providing additional production capacity. However, actual volumes will vary from year to year due to the timing of individual project start-ups; 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 changes in the amount and timing of investments that may vary depending on the oil and gas price environment. 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.

 

 

48 


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

 

 

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2015 were $31.1 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment level of $23.2 billion in 2016. The Corporation is emerging from several years of high capital expenditure levels that supported major long-plateau production projects coming on line. Lower levels of capital spending over the next few years, partly due to cost savings and capital efficiencies, are not expected to delay major project schedules nor have a material effect on our volume capacity outlook.

Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.

 

Cash Flow from Operating Activities

 

2015

Cash provided by operating activities totaled $30.3 billion in 2015, $14.8 billion lower than 2014. The major source of funds was net income including noncontrolling interests of $16.6 billion, a decrease of $17.1 billion. The noncash provision for depreciation and depletion was $18.0 billion, up $0.8 billion from the prior year. The adjustment for net gains on asset sales was $0.2 billion compared to an adjustment of $3.2 billion in 2014. Changes in operational working capital, excluding cash and debt, decreased cash in 2015 by $3.1 billion.

 

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.



Cash Flow from Investing Activities

 

2015

Cash used in investment activities netted to $23.8 billion in 2015, $3.2 billion lower than 2014. Spending for property, plant and equipment of $26.5 billion decreased $6.5 billion from 2014. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $2.4 billion compared to $4.0 billion in 2014. Additional investments and advances were $1.0 billion lower in 2015, while collection of advances was $2.5 billion lower in 2015.

 

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.

49 


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

 

 

Cash Flow from Financing Activities

 

2015

Cash used in financing activities was $7.0 billion in 2015, $10.9 billion lower than 2014. Dividend payments on common shares increased to $2.88 per share from $2.70 per share and totaled $12.1 billion, a pay-out of 75 percent of net income. During the first quarter of 2015, the Corporation issued $8.0 billion of long-term debt. Total debt increased $9.6 billion to $38.7 billion at year‑end.

ExxonMobil share of equity decreased $3.6 billion to $170.8 billion. The addition to equity for earnings was $16.2 billion. This was offset by reductions for distributions to ExxonMobil shareholders of $15.1 billion, composed of $12.1 billion in dividends and $3.0 billion of share purchases of ExxonMobil stock to reduce shares outstanding. Foreign exchange translation effects of $8.2 billion for the stronger U.S. currency reduced equity, while a $3.6 billion change in the funded status of the postretirement benefits reserves increased equity.

During 2015, Exxon Mobil Corporation purchased 48 million shares of its common stock for the treasury at a gross cost of $4.0 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 1.1 percent from 4,201 million to 4,156 million at the end of 2015. 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.

 

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.  

  

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, 2015. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

 

 

 

Payments Due by Period

 

 

Note

 

 

 

 

 

2021

 

 

 

 

Reference

 

 

 

2017-

 

and

 

 

Commitments

Number

 

2016

 

2020

 

Beyond

 

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

Long-term debt  (1) 

14

 

-

 

9,902

 

10,023

 

19,925

 

 – Due in one year  (2) 

6

 

558

 

-

 

-

 

558

Asset retirement obligations  (3) 

9

 

871

 

3,760

 

9,073

 

13,704

Pension and other postretirement obligations  (4) 

17

 

3,495

 

4,104

 

15,567

 

23,166

Operating leases  (5) 

11

 

1,653

 

2,167

 

1,057

 

4,877

Unconditional purchase obligations  (6) 

16

 

133

 

493

 

310

 

936

Take-or-pay obligations  (7) 

 

 

2,997

 

9,463

 

12,410

 

24,870

Firm capital commitments  (8) 

 

 

10,320

 

4,438

 

441

 

15,199

 

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 $9.4 billion as of December 31, 2015, 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 $1,238 million.

(2)   The amount due in one year is included in notes and loans payable of $18,762 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 2016 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. Total includes $1,621 million related to drilling rigs and related equipment.

(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 $936 million mainly pertain to pipeline throughput agreements and include $411 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 $24,870 million mainly pertain to pipeline, manufacturing supply and terminal agreements.

(8)   Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $15.2 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $8.0 billion was associated with projects in Africa, United Arab Emirates, Canada, Malaysia, Kazakhstan and Australia. 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, 2015, 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, 2015, the Corporation’s unused short-term committed lines of credit totaled approximately $6.0 billion (Note 6) and unused long-term committed lines of credit totaled approximately $0.4 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.

 

 

 

2015

 

2014

 

2013

Fixed-charge coverage ratio (times)

 

17.6

 

46.9

 

55.7

Debt to capital (percent)

 

18.0

 

13.9

 

11.2

Net debt to capital (percent)

 

16.5

 

11.9

 

9.1

 

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

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

 

U.S.

Non-U.S.

Total

 

U.S.

Non-U.S.

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Upstream (1) 

7,822

 

17,585

 

25,407

 

9,401

 

23,326

 

32,727

Downstream

1,039

 

1,574

 

2,613

 

1,310

 

1,724

 

3,034

Chemical

1,945

 

898

 

2,843

 

1,690

 

1,051

 

2,741

Other

188

 

-

 

188

 

35

 

-

 

35

 

Total

10,994

 

20,057

 

31,051

 

12,436

 

26,101

 

38,537

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Exploration expenses included.

 

 

 

 

 

 

 

 

 

Capital and exploration expenditures in 2015 were $31.1 billion, as the Corporation continued to pursue opportunities to find and produce new supplies of oil and natural gas to meet global demand for energy. The Corporation anticipates an investment level of $23.2 billion in 2016. Actual spending could vary depending on the progress of individual projects and property acquisitions.

Upstream spending of $25.4 billion in 2015 was down 22 percent from 2014, reflecting key project start-ups and capital efficiencies. Investments in 2015 included projects in the U.S. Gulf of Mexico and Alaska, U.S. onshore drilling 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 73 percent of total proved reserves at year-end 2015, and has been over 60 percent for the last ten years.

Capital investments in the Downstream totaled $2.6 billion in 2015, a decrease of $0.4 billion from 2014, mainly reflecting lower refining project spending. The Chemical capital expenditures of $2.8 billion increased $0.1 billion from 2014 with higher investments in the U.S.

 

TAXES

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Income taxes

 

5,415

 

18,015

 

24,263

 

Effective income tax rate

 

34%

 

41%

 

48%

Sales-based taxes

 

22,678

 

29,342

 

30,589

All other taxes and duties

 

29,790

 

35,515

 

36,396

 

 Total 

 

57,883

 

82,872

 

91,248

 

2015

Income, sales-based and all other taxes and duties totaled $57.9 billion in 2015, a decrease of $25.0 billion or 30 percent from 2014. Income tax expense, both current and deferred, was $5.4 billion, $12.6 billion lower than 2014, as a result of lower earnings and a lower effective tax rate. The effective tax rate was 34 percent compared to 41 percent in the prior year due primarily to a lower share of earnings in higher tax jurisdictions. Sales-based and all other taxes and duties of $52.5 billion in 2015 decreased $12.4 billion as a result of lower sales realizations.

 

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.

53 


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

 

 

ENVIRONMENTAL MATTERS

 

Environmental Expenditures

 

 

 

 

 

 

 

2015

 

2014

 

 

 

(millions of dollars)

 

 

 

 

 

 

Capital expenditures

 

1,869

 

2,666

Other expenditures

 

3,777

 

3,522

 

Total

 

5,646

 

6,188

 

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 2015 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $5.6 billion, of which $3.8 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to decrease to approximately $5 billion in 2016 and 2017, mainly reflecting lower project activity in Canada. Capital expenditures are expected to account for approximately 30 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 2015 for environmental liabilities were $371 million ($780 million in 2014) and the balance sheet reflects accumulated liabilities of $837 million as of December 31, 2015, and $1,066 million as of December 31, 2014.

 

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1) 

 

2015

 

2014

 

2013

 

 

 

Crude oil and NGL ($/barrel)

 

44.77

 

87.42

 

97.48

Natural gas ($/kcf)

 

2.95

 

4.68

 

4.60

 

 

 

 

 

 

 

(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 $375 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 $150 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 global economic conditions, political events, decisions by OPEC and other major government resource owners 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 prices. The Corporation’s assessment is that its operations will continue to be successful over the long term 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. Beginning several years ago, an extended period of increased demand for certain services and materials resulted in higher operating and capital costs. More recently, multiple market changes, including general commodity price decreases, lower oil prices and reduced upstream industry activity, have contributed to lower prices for oilfield services and materials. 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, 2018.

“Sales and Other Operating Revenue” on the Consolidated Statement of Income includes sales, excise and value-added taxes on sales transactions. When the Corporation adopts the standard, revenue will exclude sales-based taxes collected on behalf of third parties. This change in reporting will not impact earnings.

The Corporation continues to evaluate other areas of 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, together with proved reserves, are as likely as not to be recovered.

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 73 percent of total proved reserves at year-end 2015 (including both consolidated and equity company reserves), and has been over 60 percent for the last ten years.

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.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

 

56 


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

 

 

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. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used. 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, Prices and Margins on Testing for Impairment. The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. 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 for this assessment.

Potential trigger events for impairment evaluation include:

·         a significant decrease in the market price of a long-lived asset;

·         a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

·         a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

·         an accumulation of project costs significantly in excess of the amount originally expected;

·         a current-period operating loss combined with a history and forecast of operating or cash flow losses; and

·         a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

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

If there were a trigger event, 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 estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the 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. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

In light of continued weakness in the upstream industry environment in late 2015, the Corporation undertook an effort to assess its major long-lived assets most at risk for potential impairment. The results of this assessment confirm the absence of a trigger event and indicate that the future undiscounted cash flows associated with these assets substantially exceed the carrying value of the assets. The assessment reflects crude and natural gas prices that are generally consistent with the long-term price forecasts published by third-party industry experts. Critical to the long-term recoverability of certain assets is the assumption that either by supply and demand changes, or due to general inflation, prices will rise in the future. Should increases in long-term prices not materialize, certain of the Corporation’s assets will be at risk for impairment. Due to the inherent difficulty in predicting future commodity prices, and the relationship between industry prices and costs, it is not practicable to reasonably estimate a range of potential future impairments related to the Corporation’s long-lived assets.

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

57 


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

 

 

properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

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.

 

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). If crude oil, natural gas, petroleum product and chemical product prices continue in the range seen in early 2016, the Corporation could be subject to a lower of cost or market inventory valuation adjustment.

 

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 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.

58 


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

 

 

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 because tax conventions and regulatory practices do not encourage advance funding. Book reserves are established for these plans. 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 2015 was 7.00 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 5 percent and 8 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 $150 million before tax.

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

 

Litigation Contingencies

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

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

Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

59 


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

 

 

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.

  

 

60 


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, 2015.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2015, 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)

  

61 


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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 24, 2016

 

62 


CONSOLIDATED STATEMENT OF INCOME

  

 

 

 

Note

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

Number

 

2015

 

2014

 

2013

 

 

 

 

 

(millions of dollars)

Revenues and other income

 

 

 

 

 

 

 

 

Sales and other operating revenue (1)

 

 

259,488

 

394,105

 

420,836

 

Income from equity affiliates

7

 

7,644

 

13,323

 

13,927

 

Other income

 

 

1,750

 

4,511

 

3,492

 

 

Total revenues and other income

 

 

268,882

 

411,939

 

438,255

Costs and other deductions

 

 

 

 

 

 

 

 

Crude oil and product purchases

 

 

130,003

 

225,972

 

244,156

 

Production and manufacturing expenses

 

 

35,587

 

40,859

 

40,525

 

Selling, general and administrative expenses

 

 

11,501

 

12,598

 

12,877

 

Depreciation and depletion

 

 

18,048

 

17,297

 

17,182

 

Exploration expenses, including dry holes

 

 

1,523

 

1,669

 

1,976

 

Interest expense

 

 

311

 

286

 

9

 

Sales-based taxes (1)

19

 

22,678

 

29,342

 

30,589

 

Other taxes and duties

19

 

27,265

 

32,286

 

33,230

 

 

Total costs and other deductions

 

 

246,916

 

360,309

 

380,544

Income before income taxes

 

 

21,966

 

51,630

 

57,711

 

Income taxes

19

 

5,415

 

18,015

 

24,263

Net income including noncontrolling interests

 

 

16,551

 

33,615

 

33,448

 

Net income attributable to noncontrolling interests

 

 

401

 

1,095

 

868

Net income attributable to ExxonMobil

 

 

16,150

 

32,520

 

32,580

 

 

 

 

 

 

 

 

 

 

Earnings per common share (dollars) 

12

 

3.85

 

7.60

 

7.37

 

 

 

 

 

 

 

 

 

 

Earnings per common share - assuming dilution (dollars) 

12

 

3.85

 

7.60

 

7.37

 

(1)   Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013.

 

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

   

 

63 


CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

16,551

 

33,615

 

33,448

Other comprehensive income (net of income taxes)

 

 

 

 

 

 

 

Foreign exchange translation adjustment

 

(9,303)

 

(5,847)

 

(3,620)

 

Adjustment for foreign exchange translation (gain)/loss

 

 

 

 

 

 

 

 

included in net income

 

(14)

 

152

 

(23)

 

Postretirement benefits reserves adjustment (excluding amortization)

 

2,358

 

(4,262)

 

3,174

 

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs

 

1,448

 

1,111

 

1,820

 

Unrealized change in fair value of stock investments

 

33

 

(63)

 

 -  

 

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

 

27

 

3

 

 -  

 

 

Total other comprehensive income

 

(5,451)

 

(8,906)

 

1,351

Comprehensive income including noncontrolling interests

 

11,100

 

24,709

 

34,799

 

Comprehensive income attributable to noncontrolling interests

 

(496)

 

421

 

760

Comprehensive income attributable to ExxonMobil

 

11,596

 

24,288

 

34,039

 

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

  

 

64 


CONSOLIDATED BALANCE SHEET

  

 

 

 

 

Note

 

 

 

 

 

 

 

 

Reference

 

Dec. 31

 

Dec. 31

 

 

 

 

Number

 

2015

 

2014

 

 

 

 

 

 

(millions of dollars)

Assets

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

3,705

 

4,616

 

 

Cash and cash equivalents - restricted

 

 

 -  

 

42

 

 

Notes and accounts receivable, less estimated doubtful amounts

6

 

19,875

 

28,009

 

 

Inventories

 

 

 

 

 

 

 

 

Crude oil, products and merchandise

3

 

12,037

 

12,384

 

 

 

Materials and supplies

 

 

4,208

 

4,294

 

 

Other current assets

 

 

2,798

 

3,565

 

 

 

Total current assets

 

 

42,623

 

52,910

 

Investments, advances and long-term receivables

8

 

34,245

 

35,239

 

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

 

 

 

 

 

 

 

and depletion

9

 

251,605

 

252,668

 

Other assets, including intangibles, net

 

 

8,285

 

8,676

 

 

 

Total assets

 

 

336,758

 

349,493

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Notes and loans payable

6

 

18,762

 

17,468

 

 

Accounts payable and accrued liabilities

6

 

32,412

 

42,227

 

 

Income taxes payable

 

 

2,802

 

4,938

 

 

 

Total current liabilities

 

 

53,976

 

64,633

 

Long-term debt

14

 

19,925

 

11,653

 

Postretirement benefits reserves

17

 

22,647

 

25,802

 

Deferred income tax liabilities

19

 

36,818

 

39,230

 

Long-term obligations to equity companies

 

 

5,417

 

5,325

 

Other long-term obligations

 

 

21,165

 

21,786

 

 

 

Total liabilities

 

 

159,948

 

168,429

 

 

 

 

 

 

 

 

 

Commitments and contingencies

16

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

Common stock without par value

 

 

 

 

 

 

 

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

 

 

11,612

 

10,792

 

Earnings reinvested

 

 

412,444

 

408,384

 

Accumulated other comprehensive income

 

 

(23,511)

 

(18,957)

 

Common stock held in treasury

 

 

 

 

 

 

 

(3,863 million shares in 2015 and 3,818 million shares in 2014)

 

 

(229,734)

 

(225,820)

 

 

 

ExxonMobil share of equity

 

 

170,811

 

174,399

 

Noncontrolling interests

 

 

5,999

 

6,665

 

 

 

Total equity

 

 

176,810

 

181,064

 

 

 

Total liabilities and equity

 

 

336,758

 

349,493

 

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

   

 

65 


CONSOLIDATED STATEMENT OF CASH FLOWS 

  

 

 

 

 

 

Note

 

 

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

 

 

Number

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

(millions of dollars)

Cash flows from operating activities

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

 

16,551

 

33,615

 

33,448

 

Adjustments for noncash transactions

 

 

 

 

 

 

 

 

 

Depreciation and depletion

 

 

18,048

 

17,297

 

17,182

 

 

Deferred income tax charges/(credits)

 

 

(1,832)

 

1,540

 

754

 

 

Postretirement benefits expense

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) net payments

 

 

2,153

 

524

 

2,291

 

 

Other long-term obligation provisions

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) payments

 

 

(380)

 

1,404

 

(2,566)

 

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

 

 

 

 

 

 

 

 

 

earnings of equity companies

 

 

(691)

 

(358)

 

3

 

Changes in operational working capital, excluding cash and debt

 

 

 

 

 

 

 

 

Reduction/(increase)

- Notes and accounts receivable

 

 

4,692

 

3,118

 

(305)

 

 

 

 

- Inventories

 

 

(379)

 

(1,343)

 

(1,812)

 

 

 

 

- Other current assets

 

 

45

 

(68)

 

(105)

 

 

Increase/(reduction)

- Accounts and other payables

 

 

(7,471)

 

(6,639)

 

(2,498)

 

Net (gain) on asset sales

5

 

(226)

 

(3,151)

 

(1,828)

 

All other items - net

5

 

(166)

 

(823)

 

350

 

 

Net cash provided by operating activities

 

 

30,344

 

45,116

 

44,914

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

5

 

(26,490)

 

(32,952)

 

(33,669)

 

Proceeds associated with sales of subsidiaries, property, plant

 

 

 

 

 

 

 

 

 

and equipment, and sales and returns of investments

5

 

2,389

 

4,035

 

2,707

 

Decrease/(increase) in restricted cash and cash equivalents

 

 

42

 

227

 

72

 

Additional investments and advances

 

 

(607)

 

(1,631)

 

(4,435)

 

Collection of advances

 

 

842

 

3,346

 

1,124

 

 

Net cash used in investing activities

 

 

(23,824)

 

(26,975)

 

(34,201)

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

Additions to long-term debt

5

 

8,028

 

5,731

 

345

 

Reductions in long-term debt

 

 

(26)

 

(69)

 

(13)

 

Additions to short-term debt

 

 

 -  

 

 -  

 

16

 

Reductions in short-term debt

 

 

(506)

 

(745)

 

(756)

 

Additions/(reductions) in commercial paper, and debt with

 

 

 

 

 

 

 

 

 

three months or less maturity

5

 

1,759

 

2,049

 

12,012

 

Cash dividends to ExxonMobil shareholders

 

 

(12,090)

 

(11,568)

 

(10,875)

 

Cash dividends to noncontrolling interests

 

 

(170)

 

(248)

 

(304)

 

Changes in noncontrolling interests

 

 

 -  

 

 -  

 

(1)

 

Tax benefits related to stock-based awards

 

 

2

 

115

 

48

 

Common stock acquired

 

 

(4,039)

 

(13,183)

 

(15,998)

 

Common stock sold

 

 

5

 

30

 

50

 

 

Net cash used in financing activities

 

 

(7,037)

 

(17,888)

 

(15,476)

Effects of exchange rate changes on cash

 

 

(394)

 

(281)

 

(175)

Increase/(decrease) in cash and cash equivalents

 

 

(911)

 

(28)

 

(4,938)

Cash and cash equivalents at beginning of year

 

 

4,616

 

4,644

 

9,582

Cash and cash equivalents at end of year

 

 

3,705

 

4,616

 

4,644

 

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

   

 

66 


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, 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

 

Amortization of stock-based awards

 

828

 

 -  

 

 -  

 

 -  

 

828

 

 -  

 

828

 

Tax benefits related to stock-based awards

 

116

 

 -  

 

 -  

 

 -  

 

116

 

 -  

 

116

 

Other

 

(124)

 

 -  

 

 -  

 

 -  

 

(124)

 

 -  

 

(124)

 

Net income for the year

 

 -  

 

16,150

 

 -  

 

 -  

 

16,150

 

401

 

16,551

 

Dividends - common shares

 

 -  

 

(12,090)

 

 -  

 

 -  

 

(12,090)

 

(170)

 

(12,260)

 

Other comprehensive income

 

 -  

 

 -  

 

(4,554)

 

 -  

 

(4,554)

 

(897)

 

(5,451)

 

Acquisitions, at cost

 

 -  

 

 -  

 

 -  

 

(4,039)

 

(4,039)

 

 -  

 

(4,039)

 

Dispositions

 

 -  

 

 -  

 

 -  

 

125

 

125

 

 -  

 

125

Balance as of December 31, 2015

 

11,612

 

412,444

 

(23,511)

 

(229,734)

 

170,811

 

5,999

 

176,810

 

 

 

 

 

 

Held in

 

 

Common Stock Share Activity

 

Issued

 

Treasury

Outstanding

 

 

 

(millions of shares)

 

 

 

 

 

 

 

 

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

 

Acquisitions

 

 -  

 

(48)

 

(48)

 

Dispositions

 

 -  

 

3

 

3

Balance as of December 31, 2015

 

8,019

 

(3,863)

 

4,156

 

 

 

 

 

 

 

 

 

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

   

 

67 


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 2015 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

68 


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. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative such as the straight-line method is used.

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.

The Corporation performs impairment assessments whenever events or circumstances indicate that the carrying amounts of its long-lived assets (or group of assets) may not be recoverable through future operations or disposition. 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 for this assessment.

Potential trigger events for impairment evaluation include:

·         a significant decrease in the market price of a long-lived asset;

·         a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

·         a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

·         an accumulation of project costs significantly in excess of the amount originally expected;

·         a current-period operating loss combined with a history and forecast of operating or cash flow losses; and

·         a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses and other profitability reviews assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable.

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

69 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.

If there were a trigger event, 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 estimates for future crude oil and natural gas commodity prices, refining and chemical margins, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. These evaluations make use of the Corporation’s price, margin, volume, and cost assumptions developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the 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. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

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.

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

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

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

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

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

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

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

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

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

70 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2015 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, 2018.

“Sales and Other Operating Revenue” on the Consolidated Statement of Income includes sales, excise and value-added taxes on sales transactions. When the Corporation adopts the standard, revenue will exclude sales-based taxes collected on behalf of third parties. This change in reporting will not impact earnings.

The Corporation continues to evaluate other areas of the standard and its effect on the Corporation’s financial statements.

 

3. Miscellaneous Financial Information

Research and development expenses totaled $1,008 million in 2015, $971 million in 2014 and $1,044 million in 2013.

Net income included before‑tax aggregate foreign exchange transaction losses of $119 million and $225 million in 2015 and 2014, respectively, and gains of $155 million in 2013.

In 2015, 2014 and 2013, net income included a loss of $186 million, and gains of $187 million and $282 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 $4.5 billion and $10.6 billion at December 31, 2015, and 2014, respectively.

Crude oil, products and merchandise as of year-end 2015 and 2014 consist of the following:

 

 

 

 

2015

 

2014

 

 

 

    (billions of dollars)

 

 

 

 

 

 

Crude oil

 

4.2

 

4.6

Petroleum products

 

4.1

 

4.1

Chemical products

 

2.7

 

2.9

Gas/other

 

1.0

 

0.8

 

Total

 

12.0

 

12.4

71 


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, 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)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2014

(5,952)

 

 

(12,945)

 

 

(60)

 

 

(18,957)

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(8,204)

 

 

2,202

 

 

33

 

 

(5,969)

 

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

(14)

 

 

1,402

 

 

27

 

 

1,415

 

Total change in accumulated other comprehensive income

(8,218)

 

 

3,604

 

 

60

 

 

(4,554)

 

Balance as of December 31, 2015

(14,170)

 

 

(9,341)

 

 

 -  

 

 

(23,511)

 

 

Amounts Reclassified Out of Accumulated Other

 

 

 

 

 

 

Comprehensive Income - Before-tax Income/(Expense)

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

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

 

 

 

 

 

 

 

(Statement of Income line: Other income)

 

14

 

(152)

 

23

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs (1) 

 

(2,066)

 

(1,571)

 

(2,616)

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

 

 

 

 

 

 

 

(Statement of Income line: Other income)

 

(42)

 

 (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

2015

 

2014

 

2013

 

 

 

(millions of dollars)

Foreign exchange translation adjustment

170

 

292

 

218

Postretirement benefits reserves adjustment (excluding amortization)

(1,192)

 

2,009

 

(1,540)

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

adjustment included in net periodic benefit costs

(618)

 

(460)

 

(796)

Unrealized change in fair value of stock investments

(17)

 

34

 

 -  

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

(15)

 

(2)

 

 -  

Total

(1,672)

 

1,873

 

(2,118)

               

72 


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 2015, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale of service stations in Europe, the sale of Upstream properties in the U.S., the sale of ExxonMobil’s interests in Chemical and Refining joint ventures, and the pending sale of the Torrance refinery. For 2014, the amount 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. These net gains are reported in “Other income” on the Consolidated Statement of Income.

In 2015, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $358 million addition of commercial paper with maturity over three months. The gross amount issued was $8.1 billion, while the gross amount repaid was $7.7 billion.

In 2015, ExxonMobil completed an asset exchange that resulted in value received of approximately $500 million including $100 million in cash. The non-cash portion was not included in the “Sales of subsidiaries, investments, and property, plant and equipment” or the “All other items-net” lines on the Statement of Cash Flows. Capital leases of approximately $1 billion were not included in the “Additions to long-term debt” or “Additions to property, plant and equipment” lines on the Statement of Cash Flows.

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.

 

 

2015

 

2014

 

2013

 

 

(millions of dollars)

 

 

 

 

 

 

 

Cash payments for interest

 

586

 

380

 

426

 

 

 

 

 

 

 

Cash payments for income taxes

 

7,269

 

18,085

 

25,066



6. Additional Working Capital Information

 

 

 

 

Dec. 31

 

Dec. 31

 

 

 

 

2015

 

2014

 

 

 

 

(millions of dollars)

Notes and accounts receivable

 

 

 

 

 

Trade, less reserves of $107 million and $113 million

 

13,243

 

18,541

 

Other, less reserves of $4 million and $48 million

 

6,632

 

9,468

 

 

Total

 

19,875

 

28,009

 

 

 

 

 

 

 

Notes and loans payable

 

 

 

 

 

Bank loans

 

231

 

473

 

Commercial paper

 

17,973

 

16,225

 

Long-term debt due within one year

 

558

 

770

 

 

Total

 

18,762

 

17,468

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

 

 

 

 

Trade payables

 

18,074

 

25,286

 

Payables to equity companies

 

4,639

 

6,589

 

Accrued taxes other than income taxes

 

2,937

 

3,290

 

Other

 

6,762

 

7,062

 

 

Total

 

32,412

 

42,227

 

The Corporation has short-term committed lines of credit of $6.0 billion which were unused as of December 31, 2015. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was 0.4 percent and 0.3 percent at December 31, 2015, and 2014, respectively.

73 


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, and natural gas marketing 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 15 percent, 14 percent and 13 percent in the years 2015, 2014 and 2013, 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. With respect to the foregoing, each joint venture continues to comply with all applicable laws, rules and regulations. The Corporation's maximum before-tax exposure to loss from these joint ventures as of December 31, 2015, is $1.0 billion.

 

 

 

 

2015

 

2014

 

2013

Equity Company

 

 

ExxonMobil

 

ExxonMobil

 

      ExxonMobil

Financial Summary

 

Total

 

Share

 

Total

 

Share

 

Total

 

Share

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

111,866

 

34,297

 

183,708

 

55,855

 

236,161

 

68,084

Income before income taxes

 

36,379

 

10,670

 

65,549

 

19,014

 

69,454

 

19,999

Income taxes

 

11,048

 

3,019

 

20,520

 

5,684

 

21,618

 

6,069

 

Income from equity affiliates

 

25,331

 

7,651

 

45,029

 

13,330

 

47,836

 

13,930

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

32,879

 

11,244

 

49,905

 

16,802

 

62,398

 

19,545

Long-term assets

 

109,684

 

32,878

 

110,754

 

33,619

 

116,450

 

35,695

 

Total assets

 

142,563

 

44,122

 

160,659

 

50,421

 

178,848

 

55,240

Current liabilities

 

22,947

 

6,738

 

37,333

 

11,472

 

54,550

 

15,243

Long-term liabilities

 

60,388

 

17,165

 

66,231

 

19,470

 

68,857

 

20,873

 

Net assets

 

59,228

 

20,219

 

57,095

 

19,479

 

55,441

 

19,124

 

 

 

 

 

 

 

 

 

 

 

 

 

 

74 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

A list of significant equity companies as of December 31, 2015, 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

 

 

 

 

 

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 Italia s.r.l.

50

 

 

 

 

Infineum USA L.P.

50

 

 

 

 

Saudi Yanbu Petrochemical Co.

50

 

 

 



8. Investments, Advances and Long-Term Receivables

 

 

 

 

Dec. 31,

 

Dec. 31,

 

 

 

 

2015

 

2014

 

 

 

 

(millions of dollars)

Companies carried at equity in underlying assets

 

 

 

 

 

Investments

 

20,337

 

20,017

 

Advances

 

9,110

 

9,818

 

 

Total equity company investments and advances

 

29,447

 

29,835

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

 

274

 

526

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

 

 

 

 

 

of $3,040 million and $2,662 million

 

4,524

 

4,878

 

 

Total

 

34,245

 

35,239

75 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

9. Property, Plant and Equipment and Asset Retirement Obligations

 

 

 

 

December 31, 2015

 

December 31, 2014

Property, Plant and Equipment

 

Cost

 

Net

 

Cost

 

Net

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Upstream

 

347,821

 

203,822

 

347,170

 

205,308

Downstream

 

50,742

 

21,330

 

53,327

 

22,639

Chemical

 

32,481

 

16,247

 

30,717

 

14,918

Other

 

16,293

 

10,206

 

15,575

 

9,803

 

Total

 

447,337

 

251,605

 

446,789

 

252,668

 

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.

The Corporation periodically reviews the estimated asset service life of its property, plant and equipment. Effective January 1, 2016, the Corporation revised the estimated asset service life of its investments in process equipment in the Chemical segment to 25 years. This revision will not have a material impact on the Corporation’s financial statements.

Accumulated depreciation and depletion totaled $195,732 million at the end of 2015 and $194,121 million at the end of 2014. Interest capitalized in 2015, 2014 and 2013 was $482 million, $344 million and $309 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:

 

 

 

 

2015

 

2014

 

 

 

(millions of dollars)

 

 

 

 

 

 

Beginning balance

 

13,424

 

12,988

 

Accretion expense and other provisions

 

775

 

871

 

Reduction due to property sales

 

(208)

 

(151)

 

Payments made

 

(928)

 

(724)

 

Liabilities incurred

 

283

 

122

 

Foreign currency translation

 

(931)

 

(908)

 

Revisions

 

1,289

 

1,226

Ending balance

 

13,704

 

13,424

76 


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:

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Balance beginning at January 1

 

3,587

 

2,707

 

2,679

 

Additions pending the determination of proved reserves

 

847

 

1,095

 

293

 

Charged to expense

 

(5)

 

(28)

 

(52)

 

Reclassifications to wells, facilities and equipment based on the

 

 

 

 

 

 

 

 

determination of proved reserves

 

(43)

 

(160)

 

(107)

 

Divestments/Other

 

(14)

 

(27)

 

(106)

Ending balance at December 31

 

4,372

 

3,587

 

2,707

Ending balance attributed to equity companies included above

 

696

 

645

 

13



Period end capitalized suspended exploratory well costs:

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Capitalized for a period of one year or less

 

847

 

1,095

 

293

 

Capitalized for a period of between one and five years

 

2,386

 

1,659

 

1,705

 

Capitalized for a period of between five and ten years

 

826

 

544

 

470

 

Capitalized for a period of greater than ten years

 

313

 

289

 

239

Capitalized for a period greater than one year - subtotal

 

3,525

 

2,492

 

2,414

 

 

Total

 

4,372

 

3,587

 

2,707

 

 

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a 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, which includes the Rosneft joint venture exploration activity (refer to the relevant portion of Note 7).

 

 

 

 

2015

 

2014

 

2013

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

4

 

8

 

8

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

 

 

 

 

 

 

of greater than 12 months

 

55

 

53

 

50

 

 

Total

 

59

 

61

 

58

 

Of the 55 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2015, 18 projects have drilling in the preceding 12 months or exploratory activity either planned in the next two years or subject to sanctions. The remaining 37 projects are those with completed exploratory activity progressing toward development.

77 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The table below provides additional detail for those 37 projects, which total $1,154 million.

 

 

 

Years

 

 

 

Dec. 31,

Wells

 

Country/Project

2015

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

 

7

 

2001

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

 

 

 

 

 

 infrastructure. 

 - SE Longtom

 

11

 

2010

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

 - SE Remora

 

34

 

2010

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

Canada

 

 

 

 

 

 - Horn River

 

241

 

2009 - 2012

 Evaluating development alternatives to tie into planned infrastructure.

Indonesia

 

 

 

 

 

 - Alas Tua West

 

16

 

2010

 Evaluating development plan to tie into planned production facilities.

 - Cepu Gas

 

29

 

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.

 - Kalamkas

 

18

 

2006 - 2009

 Evaluating development alternatives, while continuing discussions with the

 

 

 

 

 

 government regarding development plan.

Malaysia

 

 

 

 

 

 - 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.

 - 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

 

13

 

2008 - 2009

 Evaluating development plan for tieback to existing production facilities.

 - Lavrans

 

15

 

1995 - 1999

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

 - Other (7 projects)

 

25

 

2008 - 2014

 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.

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 2015 (37 projects)

 

1,154

 

 

 

 

 

 

 

 

 

78 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

11. Leased Facilities

At December 31, 2015, 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 $4,877 million as indicated in the table. Estimated related rental income from noncancelable subleases is $32 million.

 

 

Lease Payments Under Minimum Commitments

Related

 

Drilling Rigs

 

 

 

Sublease

 

and Related

 

 

Rental

 

Equipment

Other

 

Total

 

Income

 

(millions of dollars)

 

 

 

 

 

 

 

 

2016

827

 

826

 

1,653

 

7

2017

408

 

595

 

1,003

 

6

2018

134

 

421

 

555

 

2

2019

89

 

255

 

344

 

2

2020

77

 

188

 

265

 

2

2021 and beyond

86

 

971

 

1,057

 

13

     Total

1,621

 

3,256

 

4,877

 

32

 

Net rental cost under both cancelable and noncancelable operating leases incurred during 2015, 2014 and 2013 were as follows:

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Rental cost

 

 

 

 

 

 

 

Drilling rigs and related equipment

 

1,853

 

1,763

 

1,424

 

Other

 

2,120

 

2,314

 

2,417

 

 

Total

 

3,973

 

4,077

 

3,841

 

Less sublease rental income

 

44

 

52

 

44

Net rental cost

 

3,929

 

4,025

 

3,797



12. Earnings Per Share

 

 

 

2015

 

2014

 

2013

Earnings per common share

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to ExxonMobil (millions of dollars)

 

16,150

 

32,520

 

32,580

 

 

 

 

 

 

 

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

 

4,196

 

4,282

 

4,419

 

 

 

 

 

 

 

Earnings per common share (dollars) (1)

 

3.85

 

7.60

 

7.37

 

 

 

 

 

 

 

Dividends paid per common share (dollars)

 

2.88

 

2.70

 

2.46

 

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

79 


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 $18.9 billion and $11.7 billion at December 31, 2015, and 2014, respectively, as compared to recorded book values of $18.7 billion and $11.3 billion at December 31, 2015, and 2014, respectively. The increase in the estimated fair value and book value of long-term debt reflects the Corporation’s issuance of $8.0 billion of long-term debt in the first quarter of 2015.

The fair value of long-term debt by hierarchy level at December 31, 2015, is: Level 1 $18,584 million; Level 2 $208 million; and Level 3 $62 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 $21 million at year-end 2015 and a net asset of $75 million at year-end 2014. 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 $39 million, $110 million and $(7) million during 2015, 2014 and 2013, 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.

80 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

14. Long-Term Debt

At December 31, 2015, long-term debt consisted of $19,217 million due in U.S. dollars and $708 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 $558 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 $8.0 billion of long-term debt in the first quarter of 2015. The amounts of long-term debt, including capitalized lease obligations, maturing in each of the four years after December 31, 2016, in millions of dollars, are: 2017 – $2,959; 2018 – $2,967; 2019 – $2,374; and 2020 – $1,602. At December 31, 2015, the Corporation’s unused long-term credit lines were $0.4 billion.

Summarized long-term debt at year-end 2015 and 2014 are shown in the table below:

 

 

 

 

 

2015

 

2014

 

 

 

      (millions of dollars)

 

 

Exxon Mobil Corporation

 

 

 

 

 

 

 

0.921% notes due 2017

 

1,500

 

1,500

 

 

 

Floating-rate notes due 2017 (1)

 

750

 

750

 

 

 

Floating-rate notes due 2018 (2)

 

500

 

 -  

 

 

 

1.305% notes due 2018

 

1,600

 

 -  

 

 

 

1.819% notes due 2019

 

1,750

 

1,750

 

 

 

Floating-rate notes due 2019 (3) 

 

500

 

500

 

 

 

1.912% notes due 2020

 

1,500

 

 -  

 

 

 

2.397% notes due 2022

 

1,150

 

 -  

 

 

 

Floating-rate notes due 2022 (4) 

 

500

 

 -  

 

 

 

3.176% notes due 2024

 

1,000

 

1,000

 

 

 

2.709% notes due 2025

 

1,750

 

 -  

 

 

 

3.567% notes due 2045

 

1,000

 

 -  

 

 

 

 

  

 

 

 

 

 

 

XTO Energy Inc. (5) 

 

 

 

 

 

 

 

5.650% senior notes due 2016

 

 -  

 

207

 

 

 

6.250% senior notes due 2017

 

465

 

477

 

 

 

5.500% senior notes due 2018

 

377

 

383

 

 

 

6.500% senior notes due 2018

 

463

 

474

 

 

 

6.100% senior notes due 2036

 

198

 

199

 

 

 

6.750% senior notes due 2037

 

307

 

309

 

 

 

6.375% senior notes due 2038

 

235

 

236

 

 

 

 

 

 

 

 

 

 

 

Mobil Producing Nigeria Unlimited (6) 

 

 

 

 

 

 

 

Variable notes due 2016-2019

 

101

 

399

 

 

 

 

 

 

 

 

 

 

 

Esso (Thailand) Public Company Ltd. (7) 

 

 

 

 

 

 

 

Variable notes due 2016-2020

 

83

 

121

 

 

 

 

 

 

 

 

 

 

 

Mobil Corporation

 

 

 

 

 

 

 

8.625% debentures due 2021

 

249

 

249

 

 

 

 

 

 

 

 

 

 

 

Industrial revenue bonds due 2017-2051 (8) 

 

2,611

 

2,611

 

 

Other U.S. dollar obligations (9) 

 

97

 

104

 

 

Other foreign currency obligations

 

1

 

9

 

 

Capitalized lease obligations (10) 

 

1,238

 

375

 

 

 

 

Total long-term debt

 

19,925

 

11,653

 

 

 

(1)   Average effective interest rate of 0.3% in 2015 and 0.3% in 2014.

(2)   Average effective interest rate of 0.4% in 2015.

(3)   Average effective interest rate of 0.5% in 2015 and 0.4% in 2014.

(4)   Average effective interest rate of 0.7% in 2015.

(5)   Includes premiums of $179 million in 2015 and $219 million in 2014.

(6)   Average effective interest rate of 4.6% in 2015 and 4.5% in 2014.

(7)   Average effective interest rate of 2.1% in 2015 and 2.4% in 2014.

(8)   Average effective interest rate of 0.02% in 2015 and 0.03% in 2014.

(9)   Average effective interest rate of 3.8% in 2015 and 4.2% in 2014.

(10) Average imputed interest rate of 9.2% in 2015 and 7.0% in 2014.

81 


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 2015, remaining shares available for award under the 2003 Incentive Program were 100 million.  

Restricted Stock and Restricted Stock Units. Awards totaling 9,681 thousand, 9,775 thousand, and 9,729 thousand of restricted (nonvested) common stock units were granted in 2015, 2014 and 2013, 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, 2015.

 

2015

 

 

 

 

Weighted Average

 

 

 

 

Grant-Date

Restricted stock and units outstanding

Shares

 

 

Fair Value per Share

 

(thousands)

 

 

(dollars)

 

 

 

 

 

 

 

Issued and outstanding at January 1

44,439

 

 

 

81.45

 

2014 award issued in 2015

9,758

 

 

 

95.20

 

Vested

(9,945)

 

 

 

79.86

 

Forfeited

(189)

 

 

 

82.26

 

Issued and outstanding at December 31

44,063

 

 

 

84.85

 

 

 

 

 

 

 

 

Value of restricted stock and units

 

2015

 

2014

 

2013

Grant price (dollars)

 

81.27

 

95.20

 

94.47

 

 

 

 

 

 

 

Value at date of grant:

 

(millions of dollars)

Restricted stock and units settled in stock

 

727

 

858

 

843

Units settled in cash

 

60

 

73

 

76

Total value

 

787

 

931

 

919

 

As of December 31, 2015, there was $2,222 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 $855 million, $831 million and $854 million for 2015, 2014 and 2013, respectively. The income tax benefit recognized in income related to this compensation expense was $78 million, $76 million and $78 million for the same periods, respectively. The fair value of shares and units vested in 2015, 2014 and 2013 was $808 million, $946 million and $1,040 million, respectively. Cash payments of $64 million, $73 million and $67 million for vested restricted stock units settled in cash were made in 2015, 2014 and 2013, respectively.

82 


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, 2015, 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, 2015

 

 

 

 

 

 

Equity Company

Other Third-Party

 

 

 

 

 

Obligations (1) 

Obligations

 

Total

 

 

 

 

 

 

(millions of dollars)

 

 

Guarantees

 

 

 

 

 

 

 

 

 

Debt-related

 

98

 

 

35

 

 

133

 

Other

 

2,539

 

 

4,553

 

 

7,092

 

 

Total

 

2,637

 

 

4,588

 

 

7,225

 

 

 

 

 

 

 

 

 

 

 

(1) ExxonMobil share.

 

 

 

 

 

 

 

 

 

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

 

 

 

Payments Due by Period

 

 

 

 

2017-

2021 and

 

 

 

2016

 

2020

Beyond

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Unconditional purchase obligations (1) 

 

133

 

493

 

310

 

936

 

(1)   Undiscounted obligations of $936 million mainly pertain to pipeline throughput agreements and include $411 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $144 million, totaled $792 million.

83 


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). 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.

On June 12, 2015, the Tribunal rejected in its entirety Venezuela’s October 23, 2014, application to revise the ICSID award. The Tribunal also lifted the associated stay of enforcement that had been entered upon the filing of the application to revise.

Still pending is Venezuela’s February 2, 2015, application to ICSID seeking annulment of the ICSID award. That 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. A separate stay of the ICSID award was entered following the filing of the annulment application. On July 7, 2015, the ICSID Committee considering the annulment application heard arguments from the parties on whether to lift the stay of the award associated with that application. On July 28, 2015, the Committee issued an order that would lift the stay of enforcement unless, within 30 days, Venezuela delivered a commitment to pay the award if the application to annul is denied. On September 17, 2015, the Committee ruled that Venezuela had complied with the requirement to submit a written commitment to pay the award and so left the stay of enforcement in place. A hearing on Venezuela’s application for annulment, previously scheduled for January 25-27, 2016, has been rescheduled for March 8-9, 2016.  

The United States District Court for the Southern District of New York entered judgment on the ICSID award on October 10, 2014. Motions filed by Venezuela to vacate that judgment on procedural grounds and 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, were denied on February 13, 2015, and March 4, 2015, respectively. On March 9, 2015, Venezuela filed a notice of appeal of the court’s actions on the two motions. Oral arguments on this appeal were held before the United States Court of Appeals for the Second Circuit on January 7, 2016.

The District Court’s judgment on the ICSID award is currently stayed until such time as ICSID’s stay of the award entered following Venezuela’s filing of its application to annul has 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 appealed that judgment to the Court of Appeal, Abuja Judicial Division. 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. NNPC has moved to dismiss the lawsuit. Proceedings in the Southern District of New York are currently stayed. 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. 

84 


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

 

 

 

2015

 

2014

 

2015

 

2014

 

2015

 

2014

 

 

 

(percent)

Weighted-average assumptions used to determine

 

 

 

 

 

 

 

 

 

 

 

 

benefit obligations at December 31

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

4.25

 

4.00

 

3.60

 

3.10

 

4.25

 

4.00

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

4.80

 

5.30

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

Change in benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1

 

20,529

 

17,304

 

30,047

 

27,357

 

9,436

 

7,868

 

Service cost

 

864

 

677

 

689

 

590

 

170

 

140

 

Interest cost

 

785

 

807

 

850

 

1,138

 

346

 

383

 

Actuarial loss/(gain)

 

(545)

 

3,192

 

(1,517)

 

4,929

 

(617)

 

1,522

 

Benefits paid (1) (2)

 

(2,050)

 

(1,427)

 

(1,287)

 

(1,366)

 

(482)

 

(525)

 

Foreign exchange rate changes

 

 -  

 

 -  

 

(3,242)

 

(2,540)

 

(106)

 

(48)

 

Amendments, divestments and other

 

 -  

 

(24)

 

(423)

 

(61)

 

(465)

 

96

Benefit obligation at December 31

 

19,583

 

20,529

 

25,117

 

30,047

 

8,282

 

9,436

Accumulated benefit obligation at December 31

 

15,666

 

16,385

 

22,362

 

26,318

 

 -  

 

 -  

 

(1)   Benefit payments for funded and unfunded plans.

(2)   For 2015 and 2014, other postretirement benefits paid are net of $15 million and $21 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 2017 and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $88 million and the postretirement benefit obligation by $963 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $66 million and the postretirement benefit obligation by $764 million.

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2015

 

2014

 

2015

 

2014

 

2015

 

2014

 

 

 

(millions of dollars)

Change in plan assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

12,915

 

11,190

 

20,095

 

19,283

 

468

 

620

 

Actual return on plan assets

 

(307)

 

1,497

 

918

 

3,153

 

 -  

 

41

 

Foreign exchange rate changes

 

 -  

 

 -  

 

(2,109)

 

(1,738)

 

 -  

 

 -  

 

Company contribution

 

 -  

 

1,476

 

515

 

554

 

42

 

31

 

Benefits paid (1) 

 

(1,623)

 

(1,248)

 

(890)

 

(912)

 

(96)

 

(224)

 

Other

 

 -  

 

 -  

 

(112)

 

(245)

 

 -  

 

 -  

Fair value at December 31

 

10,985

 

12,915

 

18,417

 

20,095

 

414

 

468

 

(1)   Benefit payments for funded plans.

85 


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.

 

 

 

2015

 

2014

 

2015

 

2014

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

Balance at December 31

 

 

 

 

 

 

 

 

 

Funded plans

 

(5,782)

 

(4,590)

 

(588)

 

(2,113)

 

Unfunded plans

 

(2,816)

 

(3,024)

 

(6,112)

 

(7,839)

Total

 

(8,598)

 

(7,614)

 

(6,700)

 

(9,952)

 

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

 

 

 

2015

 

2014

 

2015

 

2014

 

2015

 

2014

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31  (1) 

 

(8,598)

 

(7,614)

 

(6,700)

 

(9,952)

 

(7,868)

 

(8,968)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in the consolidated balance

 

 

 

 

 

 

 

 

 

 

 

 

 

sheet consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

 -  

 

 -  

 

454

 

302

 

 -  

 

 -  

 

Current liabilities

 

(311)

 

(340)

 

(299)

 

(325)

 

(363)

 

(369)

 

Postretirement benefits reserves

 

(8,287)

 

(7,274)

 

(6,855)

 

(9,929)

 

(7,505)

 

(8,599)

Total recorded

 

(8,598)

 

(7,614)

 

(6,700)

 

(9,952)

 

(7,868)

 

(8,968)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

6,138

 

6,589

 

6,413

 

9,642

 

2,171

 

2,997

 

Prior service cost

 

21

 

27

 

(83)

 

429

 

(460)

 

51

Total recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

 

6,159

 

6,616

 

6,330

 

10,071

 

1,711

 

3,048

 

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

86 


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

 

 

 

 

 

2015

 

2014

 

2013

 

2015

 

2014

 

2013

 

2015

 

2014

 

2013

Weighted-average assumptions used to

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

determine net periodic benefit cost for

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

years ended December 31

(percent)

 

Discount rate

 

4.00

 

5.00

 

4.00

 

3.10

 

4.30

 

3.80

 

4.00

 

5.00

 

4.00

 

Long-term rate of return on funded assets

 

7.00

 

7.25

 

7.25

 

5.90

 

6.30

 

6.40

 

7.00

 

7.25

 

7.25

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

5.75

 

5.30

 

5.40

 

5.50

 

5.75

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Components of net periodic benefit cost

 

(millions of dollars)

 

Service cost

 

864

 

677

 

801

 

689

 

590

 

697

 

170

 

140

 

176

 

Interest cost

 

785

 

807

 

749

 

850

 

1,138

 

1,076

 

346

 

383

 

352

 

Expected return on plan assets

 

(830)

 

(799)

 

(835)

 

(1,094)

 

(1,193)

 

(1,128)

 

(28)

 

(37)

 

(41)

 

Amortization of actuarial loss/(gain)

 

544

 

409

 

646

 

730

 

628

 

852

 

206

 

116

 

228

 

Amortization of prior service cost

 

6

 

8

 

7

 

87

 

120

 

117

 

(24)

 

14

 

21

 

Net pension enhancement and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    curtailment/settlement cost

 

499

 

276

 

723

 

 22  

 

 -  

 

22

 

 -  

 

 -  

 

 -  

Net periodic benefit cost

 

1,868

 

1,378

 

2,091

 

1,284

 

1,283

 

1,636

 

670

 

616

 

736

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in amounts recorded in accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

592

 

2,494

 

(1,302)

 

(1,375)

 

2,969

 

(1,938)

 

(589)

 

1,518

 

(1,290)

 

Amortization of actuarial (loss)/gain

 

(1,043)

 

(685)

 

(1,369)

 

(752)

 

(628)

 

(874)

 

(206)

 

(116)

 

(228)

 

Prior service cost/(credit)

 

 -  

 

(25)

 

 -  

 

(401)

 

(70)

 

30

 

(535)

 

 -  

 

 -  

 

Amortization of prior service (cost)/credit

 

(6)

 

(8)

 

(7)

 

(87)

 

(120)

 

(117)

 

24

 

(14)

 

(21)

 

Foreign exchange rate changes

 

 -  

 

 -  

 

 -  

 

(1,126)

 

(688)

 

(155)

 

(31)

 

(8)

 

(10)

Total recorded in other comprehensive income

 

(457)

 

1,776

 

(2,678)

 

(3,741)

 

1,463

 

(3,054)

 

(1,337)

 

1,380

 

(1,549)

Total recorded in net periodic benefit cost and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    other comprehensive income, before tax

 

1,411

 

3,154

 

(587)

 

(2,457)

 

2,746

 

(1,418)

 

(667)

 

1,996

 

(813)

 

Costs for defined contribution plans were $405 million, $393 million and $392 million in 2015, 2014 and 2013, respectively.

87 


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

 

 

 

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

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

 

 

 

 

 

 

 

 

U.S. pension

 

 

457

 

(1,776)

 

2,678

 

Non-U.S. pension

 

 

3,741

 

(1,463)

 

3,054

 

Other postretirement benefits

 

 

1,337

 

(1,380)

 

1,549

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

 

 

5,535

 

(4,619)

 

7,281

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

 

 

(1,810)

 

1,549

 

(2,336)

(Charge)/credit to investment in equity companies

 

 

81

 

(81)

 

49

(Charge)/credit to other comprehensive income including noncontrolling

 

 

 

 

 

 

 

interests, after tax

 

 

3,806

 

(3,151)

 

4,994

Charge/(credit) to equity of noncontrolling interests

 

 

(202)

 

85

 

(279)

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

 

 

3,604

 

(3,066)

 

4,715

 

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 the major non-U.S. plans 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.

88 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The 2015 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, 2015, Using:

 

 

 

at December 31, 2015, Using:

 

 

 

 

 

 

Level 1

 

Level 2

 

 

Level 3

 

 

Total

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

 

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

1,992

 (1) 

 -  

 

 

1,992

 

 

 -  

 

 

3,179

 (1) 

 -  

 

 

3,179

 

 

Non-U.S.

 

 -  

 

1,775

 (1) 

 -  

 

 

1,775

 

 

179

 (2) 

3,429

 (1) 

 -  

 

 

3,608

 

Private equity

 

 -  

 

 -  

 

 

595

 (3) 

595

 

 

 -  

 

 

 -  

 

 

581

 (3) 

581

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

4,161

 (4) 

 -  

 

 

4,161

 

 

 -  

 

 

2,561

 (4) 

 -  

 

 

2,561

 

 

Government

 

 -  

 

2,394

 (4) 

 -  

 

 

2,394

 

 

243

 (5) 

8,125

 (4) 

 -  

 

 

8,368

 

 

Asset-backed

 

 -  

 

3

 (4) 

 -  

 

 

3

 

 

 -  

 

 

71

 (4) 

 -  

 

 

71

 

Real estate funds

 

 -  

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 

 -  

 

 -  

 

Cash

 

 -  

 

50

 (6) 

 -  

 

 

50

 

 

11

 

 

12

 (7) 

 -  

 

 

23

Total at fair value

 

 -  

 

10,375

 

 

595

 

 

10,970

 

 

433

 

 

17,377

 

 

581

 

 

18,391

 

Insurance contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

15

 

 

 

 

 

 

 

 

 

 

 

26

Total plan assets

 

 

 

 

 

 

 

 

 

10,985

 

 

 

 

 

 

 

 

 

 

 

18,417

 

(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 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.

(7)   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, 2015, Using:

 

 

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 -  

 

 

96

 (1) 

 -  

 

 

96

 

 

Non-U.S.

 

 -  

 

 

67

 (1) 

 -  

 

 

67

 

Private equity

 

 -  

 

 

 -  

 

 

 -  

 

 -  

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

 -  

 

 

79

 (2) 

 -  

 

 

79

 

 

Government

 

 -  

 

 

170

 (2) 

 -  

 

 

170

 

 

Asset-backed

 

 -  

 

 

1

 (2) 

 -  

 

 

1

 

Cash

 

 -  

 

 

1

 

 

 -  

 

 

1

Total at fair value

 

 -  

 

 

414

 

 

 -  

 

 

414

 

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

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

 

The change in the fair value in 2015 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

 

 

 

2015

 

 

Pension

 

 

Other

 

 

U.S.

 

 

Non-U.S.

 

 

Postretirement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Private

 

 

Private

 

Real

 

 

Private

 

 

Equity

 

 

Equity

 

Estate

 

 

Equity

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

562

 

 

 

535

 

57

 

 

2

 

Net realized gains/(losses)

 

1

 

 

 

26

 

(5)

 

 

 -  

 

Net unrealized gains/(losses)

 

106

 

 

 

64

 

 -  

 

 

 -  

 

Net purchases/(sales)

 

(74)

 

 

 

(44)

 

(52)

 

 

(2)

 

Fair value at December 31

 

595

 

 

 

581

 

 -  

 

 

 -  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

90 


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:

 

 

 

 

 

 

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.

   

  

91 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Other Postretirement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2014, Using:

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

92 


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.

 

 

 

2015

 

2014

 

 

2015

 

2014

 

 

(millions of dollars)

For funded  pension plans with an accumulated benefit obligation

 

 

 

 

 

 

 

 

 

 

in excess of plan assets:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

16,767

 

17,505

 

 

1,827

 

5,031

 

Accumulated benefit obligation

 

13,913

 

14,493

 

 

1,373

 

4,590

 

Fair value of plan assets

 

10,985

 

12,915

 

 

1,299

 

3,890

 

 

 

 

 

 

 

 

 

 

 

For unfunded  pension plans:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

2,816

 

3,024

 

 

6,112

 

7,839

 

Accumulated benefit obligation

 

1,753

 

1,892

 

 

5,290

 

6,573

 

 

 

 

 

 

 

 

Other

 

 

 

Pension Benefits

 

Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

(millions of dollars)

Estimated 2016 amortization from accumulated other comprehensive income:

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)  (1) 

 

930

 

543

 

 

152

 

Prior service cost  (2) 

 

6

 

55

 

 

(30)

 

(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 2016

 

2,000

 

525

 

 -  

 

 

 -  

 

Benefit payments expected in:

 

 

 

 

 

 

 

 

 

 

 

2016

 

1,548

 

1,145

 

457

 

 

24

 

 

2017

 

1,491

 

1,128

 

470

 

 

25

 

 

2018

 

1,411

 

1,178

 

481

 

 

26

 

 

2019

 

1,382

 

1,193

 

490

 

 

28

 

 

2020

 

1,342

 

1,227

 

497

 

 

29

 

 

2021 - 2025

 

6,594

 

6,359

 

2,518

 

 

170

 

 

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.

93 


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 $100 million and $129 million in 2015 and 2014, 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, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

(1,079)

 

8,180

 

 

1,901

 

4,656

 

 

2,386

 

2,032

 

 

(1,926)

 

16,150

Earnings of equity companies included above

 

226

 

5,831

 

 

170

 

444

 

 

144

 

1,235

 

 

(406)

 

7,644

Sales and other operating revenue (1) 

 

8,241

 

15,812

 

 

73,063

 

134,230

 

 

10,880

 

17,254

 

 

8

 

259,488

Intersegment revenue

 

4,344

 

20,839

 

 

12,440

 

22,166

 

 

7,442

 

5,168

 

 

274

 

 -  

Depreciation and depletion expense

 

5,301

 

9,227

 

 

664

 

1,003

 

 

375

 

654

 

 

824

 

18,048

Interest revenue

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

 -  

 

 -  

 

 

46

 

46

Interest expense

 

26

 

27

 

 

8

 

4

 

 

 -  

 

1

 

 

245

 

311

Income taxes

 

(879)

 

4,703

 

 

866

 

1,325

 

 

646

 

633

 

 

(1,879)

 

5,415

Additions to property, plant and equipment

 

6,915

 

14,561

 

 

916

 

1,477

 

 

1,865

 

629

 

 

1,112

 

27,475

Investments in equity companies

 

5,160

 

10,980

 

 

95

 

1,179

 

 

125

 

3,025

 

 

(227)

 

20,337

Total assets

 

93,648

 

155,316

 

 

16,498

 

29,808

 

 

10,174

 

18,236

 

 

13,078

 

336,758

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

(1)  Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

   

94 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Geographic

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue  (1) 

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

92,184

 

148,713

 

152,820

Non-U.S.

 

167,304

 

245,392

 

268,016

 

Total

 

259,488

 

394,105

 

420,836

 

 

 

 

 

 

 

 

Significant non-U.S. revenue sources include:

 

 

 

 

 

 

 

United Kingdom

 

23,651

 

31,346

 

34,061

 

Canada

 

22,876

 

36,072

 

35,924

 

Italy

 

13,795

 

18,880

 

19,273

 

Belgium

 

13,154

 

20,953

 

20,973

 

France

 

11,808

 

17,639

 

18,444

 

Singapore

 

10,790

 

15,407

 

15,623

 

Germany

 

10,045

 

14,816

 

15,701

 

(1)  Sales and other operating revenue includes sales-based taxes of $22,678 million for 2015, $29,342 million for 2014 and $30,589 million for 2013. See Note 1, Summary of Accounting Policies.

 

Long-lived assets

 

2015

 

2014

 

2013

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

107,039

 

104,000

 

98,271

Non-U.S.

 

144,566

 

148,668

 

145,379

 

Total

 

251,605

 

252,668

 

243,650

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

Canada

 

39,775

 

43,858

 

41,522

 

Australia

 

15,894

 

15,328

 

14,258

 

Nigeria

 

12,222

 

12,265

 

12,343

 

Kazakhstan

 

9,705

 

9,138

 

8,530

 

Singapore

 

9,681

 

9,620

 

9,570

 

Angola

 

8,777

 

9,057

 

8,262

 

Papua New Guinea

 

5,985

 

6,099

 

5,768

95 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

19. Income, Sales-Based and Other Taxes

 

 

 

 

 

 

 

 

2015

 

 

 

 

 

2014

 

 

 

 

 

2013

 

 

 

 

 

 

 

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

 

 -  

 

7,126

 

7,126

 

1,456

 

14,755

 

16,211

 

1,073

 

22,115

 

23,188

 

 

Deferred - net

 

(1,166)

 

(571)

 

(1,737)

 

900

 

1,398

 

2,298

 

(116)

 

757

 

641

 

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

 

38

 

 -  

 

38

 

5

 

 -  

 

5

 

37

 

 -  

 

37

 

 

 

Total federal and non-U.S.

 

(1,128)

 

6,555

 

5,427

 

2,361

 

16,153

 

18,514

 

994

 

22,872

 

23,866

 

State (1) 

 

(12)

 

 -  

 

(12)

 

(499)

 

 -  

 

(499)

 

397

 

 -  

 

397

 

 

 

Total income tax expense

 

(1,140)

 

6,555

 

5,415

 

1,862

 

16,153

 

18,015

 

1,391

 

22,872

 

24,263

Sales-based taxes

 

6,402

 

16,276

 

22,678

 

6,310

 

23,032

 

29,342

 

5,992

 

24,597

 

30,589

All other taxes and duties

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other taxes and duties

 

162

 

27,103

 

27,265

 

378

 

31,908

 

32,286

 

955

 

32,275

 

33,230

 

Included in production and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

manufacturing expenses

 

1,157

 

828

 

1,985

 

1,454

 

1,179

 

2,633

 

1,318

 

1,182

 

2,500

 

Included in SG&A expenses

 

150

 

390

 

540

 

155

 

441

 

596

 

150

 

516

 

666

 

 

Total other taxes and duties

 

1,469

 

28,321

 

29,790

 

1,987

 

33,528

 

35,515

 

2,423

 

33,973

 

36,396

 

 

 

Total

 

6,731

 

51,152

 

57,883

 

10,159

 

72,713

 

82,872

 

9,806

 

81,442

 

91,248

 

(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 a net charge of $177 million in 2015 and net credits of $40 million in 2014 and $310 million in 2013 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 2015, 2014 and 2013 is as follows:

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

(millions of dollars)

Income before income taxes

 

 

 

 

 

 

 

United States

 

147

 

9,080

 

9,746

 

Non-U.S.

 

21,819

 

42,550

 

47,965

 

 

Total

 

21,966

 

51,630

 

57,711

Theoretical tax

 

7,688

 

18,071

 

20,199

Effect of equity method of accounting

 

(2,675)

 

(4,663)

 

(4,874)

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

 

1,415

 

5,442

 

10,528

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

 

38

 

5

 

37

State taxes, net of federal tax benefit

 

(8)

 

(324)

 

258

Other

 

(1,043)

 

(516)

 

(1,885)

 

 

Total income tax expense

 

5,415

 

18,015

 

24,263

 

 

 

 

 

 

 

 

 

Effective tax rate calculation

 

 

 

 

 

 

Income taxes

 

5,415

 

18,015

 

24,263

ExxonMobil share of equity company income taxes

 

3,011

 

5,678

 

6,061

 

 

Total income taxes

 

8,426

 

23,693

 

30,324

Net income including noncontrolling interests

 

16,551

 

33,615

 

33,448

 

 

Total income before taxes

 

24,977

 

57,308

 

63,772

 

 

 

 

 

 

 

 

 

Effective income tax rate

 

34%

 

41%

 

48%

96 


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:

 

2015

 

2014

 

 

 

(millions of dollars)

 

 

 

 

 

 

Property, plant and equipment

 

49,409

 

51,643

Other liabilities

 

4,613

 

4,359

 

Total deferred tax liabilities

 

54,022

 

56,002

 

 

 

 

 

 

Pension and other postretirement benefits

 

(6,286)

 

(8,140)

Asset retirement obligations

 

(6,277)

 

(6,162)

Tax loss carryforwards

 

(4,983)

 

(4,099)

Other assets

 

(5,592)

 

(6,446)

 

Total deferred tax assets

 

(23,138)

 

(24,847)

 

 

 

 

 

 

Asset valuation allowances

 

1,730

 

2,570

 

Net deferred tax liabilities

 

32,614

 

33,725

 

In 2015, asset valuation allowances of $1,730 million decreased by $840 million and included net provisions of $681 million and effects of foreign currency translation of $159 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

 

2015

 

2014

 

 

 

(millions of dollars)

 

 

 

 

 

 

Other current assets

 

(1,329)

 

(2,001)

Other assets, including intangibles, net

 

(3,421)

 

(3,955)

Accounts payable and accrued liabilities

 

546

 

451

Deferred income tax liabilities

 

36,818

 

39,230

 

Net deferred tax liabilities

 

32,614

 

33,725

 

The Corporation had $51 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. that were retained to fund prior and future capital project expenditures. Deferred taxes have not been recorded for potential future tax obligations as these earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2015, it is not practical to estimate the unrecognized deferred tax liability associated with these earnings given the future availability of foreign tax credits and uncertainties about the timing of potential remittances.

97 


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

2015

 

2014

 

2013

 

 

(millions of dollars)

 

 

 

 

 

 

 

Balance at January 1

8,986

 

7,838

 

7,663

 

Additions based on current year's tax positions

903

 

1,454

 

1,460

 

Additions for prior years' tax positions

496

 

448

 

464

 

Reductions for prior years' tax positions

(190)

 

(532)

 

(249)

 

Reductions due to lapse of the statute of limitations

(4)

 

(117)

 

(588)

 

Settlements with tax authorities

(725)

 

(43)

 

(849)

 

Foreign exchange effects/other

(70)

 

(62)

 

(63)

Balance at December 31

9,396

 

8,986

 

7,838

 

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 2015, 2014 and 2013 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. In the United States, the Corporation has various U.S. federal income tax positions at issue with the Internal Revenue Service for tax years 2006-2011. Unfavorable resolution of these issues would not have a materially adverse effect on the Corporation’s net income or liquidity. The Internal Revenue Service has not completed its audit of tax years after 2011.

It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 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 - 2015

 

 

Angola

2009 - 2015

 

 

Australia

2005, 2008 - 2015

 

 

Canada

2008 - 2015

 

 

Equatorial Guinea

2007 - 2015

 

 

Malaysia

2009 - 2015

 

 

Nigeria

2005 - 2015

 

 

Norway

2007 - 2015

 

 

Qatar

2009 - 2015

 

 

Russia

2012 - 2015

 

 

United Kingdom

2011 - 2015

 

 

United States

2006 - 2015

 

 

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 $39 million and $42 million in interest expense on income tax reserves in 2015 and 2014, respectively. 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 related interest payable balances were $223 million and $205 million at December 31, 2015, and 2014, respectively.

  

 

98 


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 $831 million in 2015, $3,223 million in 2014, and $886 million in 2013. 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

4,830

 

1,756

 

3,933

 

1,275

 

2,651

 

1,408

 

15,853

 

 

Transfers

 

2,557

 

2,858

 

2,024

 

8,135

 

4,490

 

608

 

20,672

 

 

 

 

7,387

 

4,614

 

5,957

 

9,410

 

7,141

 

2,016

 

36,525

 

Production costs excluding taxes

 

4,252

 

3,690

 

2,232

 

1,993

 

1,562

 

527

 

14,256

 

Exploration expenses

 

182

 

473

 

187

 

319

 

254

 

108

 

1,523

 

Depreciation and depletion

 

5,054

 

1,315

 

1,641

 

3,874

 

1,569

 

392

 

13,845

 

Taxes other than income

 

630

 

111

 

200

 

734

 

706

 

171

 

2,552

 

Related income tax

 

(976)

 

(79)

 

807

 

1,556

 

2,117

 

238

 

3,663

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

(1,755)

 

(896)

 

890

 

934

 

933

 

580

 

686

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

608

 

-

 

2,723

 

-

 

11,174

 

-

 

14,505

 

 

Transfers

 

459

 

-

 

31

 

-

 

379

 

-

 

869

 

 

 

 

1,067

 

-

 

2,754

 

-

 

11,553

 

-

 

15,374

 

Production costs excluding taxes

 

554

 

-

 

565

 

-

 

422

 

-

 

1,541

 

Exploration expenses

 

12

 

-

 

21

 

-

 

18

 

-

 

51

 

Depreciation and depletion

 

271

 

-

 

146

 

-

 

457

 

-

 

874

 

Taxes other than income

 

47

 

-

 

1,258

 

-

 

3,197

 

-

 

4,502

 

Related income tax

 

-

 

-

 

263

 

-

 

2,559

 

-

 

2,822

 

Results of producing activities for equity companies

 

183

 

-

 

501

 

-

 

4,900

 

-

 

5,584

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

(1,572)

 

(896)

 

1,391

 

934

 

5,833

 

580

 

6,270

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

99 


   

  

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

100 


   

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $14,685 million less at year-end 2015 and $12,856 million less at year-end 2014 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, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

15,989

 

2,202

 

143

 

873

 

1,648

 

741

 

21,596

 

 

- Unproved

 

23,071

 

4,014

 

44

 

367

 

409

 

116

 

28,021

 

 

Total property costs

 

 

39,060

 

6,216

 

187

 

1,240

 

2,057

 

857

 

49,617

 

Producing assets

 

 

84,270

 

38,108

 

36,262

 

49,621

 

32,359

 

9,414

 

250,034

 

Incomplete construction

 

 

6,980

 

5,708

 

1,928

 

4,395

 

8,620

 

4,564

 

32,195

 

 

Total capitalized costs

 

 

130,310

 

50,032

 

38,377

 

55,256

 

43,036

 

14,835

 

331,846

 

Accumulated depreciation and depletion

 

46,864

 

13,873

 

29,747

 

31,579

 

16,073

 

4,573

 

142,709

 

Net capitalized costs for consolidated subsidiaries

 

83,446

 

36,159

 

8,630

 

23,677

 

26,963

 

10,262

 

189,137

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

78

 

-

 

4

 

-

 

-

 

-

 

82

 

 

- Unproved

 

14

 

-

 

-

 

-

 

59

 

-

 

73

 

 

Total property costs

 

 

92

 

-

 

4

 

-

 

59

 

-

 

155

 

Producing assets

 

 

6,181

 

-

 

5,089

 

-

 

8,563

 

-

 

19,833

 

Incomplete construction

 

 

194

 

-

 

77

 

-

 

3,727

 

-

 

3,998

 

 

Total capitalized costs

 

 

6,467

 

-

 

5,170

 

-

 

12,349

 

-

 

23,986

 

Accumulated depreciation and depletion

 

2,122

 

-

 

3,916

 

-

 

5,563

 

-

 

11,601

 

Net capitalized costs for equity companies

 

4,345

 

-

 

1,254

 

-

 

6,786

 

-

 

12,385

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

101 


   

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 2015 were $21,887 million, down $7,228 million from 2014, due primarily to lower development costs and property acquisition costs. In 2014 costs were $29,115 million, down $4,508 million from 2013, due primarily to lower property acquisition costs and development costs. Total equity company costs incurred in 2015 were $1,464 million, down $1,213 million from 2014, 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 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

6

 

-

 

-

 

-

 

31

 

-

 

37

 

 

 

- Unproved

 

305

 

39

 

-

 

93

 

1

 

2

 

440

 

 

Exploration costs

 

 

195

 

621

 

411

 

425

 

405

 

157

 

2,214

 

 

Development costs

 

 

6,774

 

3,764

 

1,439

 

3,149

 

3,068

 

1,002

 

19,196

 

 

Total costs incurred for consolidated subsidiaries

 

7,280

 

4,424

 

1,850

 

3,667

 

3,505

 

1,161

 

21,887

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

 

 

- Unproved

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

 

Exploration costs

 

 

9

 

-

 

41

 

-

 

(19)

 

-

 

31

 

 

Development costs

 

 

411

 

-

 

143

 

-

 

879

 

-

 

1,433

 

 

Total costs incurred for equity companies

 

420

 

-

 

184

 

-

 

860

 

-

 

1,464

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

102 


   

Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2013, 2014, and 2015.

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 (SEC) 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.

When crude oil and natural gas prices are in the range seen in late 2015 and early 2016 for an extended period of time, under the SEC definition of proved reserves, certain quantities of oil and natural gas, such as oil sands operations in Canada and natural gas operations in North America could temporarily not qualify as proved reserves. Amounts that could be required to be de-booked as proved reserves on an SEC basis are subject to being re-booked as proved reserves at some point in the future when price levels recover, costs decline, or operating efficiencies occur. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to ExxonMobil. We do not expect any temporary changes in reported proved reserves under SEC definitions to affect the operation of the underlying projects or to alter our outlook for future production volumes.

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 2015 that were associated with production sharing contract arrangements was 10 percent of liquids, 10 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 2014 year-end proved reserves and 2015 year-end proved reserves primarily reflect extensions and purchases in the United States and Asia, and revisions in the United States and Canada. Due to low natural gas prices during 2015, the Corporation reclassified approximately 4,800 billion cubic feet of natural gas reserves in the United States which no longer meet the SEC definition of proved reserves.

  

103 


   

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, 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

(See footnote on next page)

104 


   

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, 2015

2,108

282

199

1,102

2,132

141

5,964

 

1,092

 

4,233

 

 

534

 

11,823

 

Revisions

(150)

(10)

46

48

123

(4)

53

 

(95)

 

433

 

 

68

 

459

 

Improved recovery

-

-

2

-

-

-

2

 

-

 

-

 

 

-

 

2

 

Purchases

161

3

1

-

-

-

165

 

46

 

-

 

 

-

 

211

 

Sales

(9)

-

(1)

-

(2)

-

(12)

 

(1)

 

-

 

 

-

 

(13)

 

Extensions/discoveries

387

2

-

-

698

-

1,087

 

101

 

-

 

 

-

 

1,188

 

Production

(119)

(17)

(63)

(187)

(126)

(12)

(524)

 

(65)

 

(106)

 

 

(21)

 

(716)

December 31, 2015

2,378

260

184

963

2,825

125

6,735

 

1,078

 

4,560

 

 

581

 

12,954

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2015

328

-

27

-

1,100

-

1,455

 

435

 

-

 

 

-

 

1,890

 

Revisions

(52)

-

(1)

-

65

-

12

 

5

 

-

 

 

-

 

17

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Production

(22)

-

(1)

-

(88)

-

(111)

 

(26)

 

-

 

 

-

 

(137)

December 31, 2015

254

-

25

-

1,077

-

1,356

 

414

 

-

 

 

-

 

1,770

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2015

2,632

260

209

963

3,902

125

8,091

 

1,492

 

4,560

 

 

581

 

14,724

 

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 11 million barrels in 2013, 8 million barrels in 2014 and 7 million barrels in 2015, as well as proved developed reserves of 9 million barrels in 2013, 5 million barrels in 2014 and 4 million barrels in 2015, and in addition, proved undeveloped reserves of 2 million barrels in 2013, 3 million barrels in 2014 and 3 million in 2015, in which there is a 30.4 percent noncontrolling interest.

   

  

105 


   

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, 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

 

4,233

 

534

 

13,713

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,427

101

 

192

900

1,707

107

4,434

 

4,108

 

581

 

9,123

 

 

Equity companies

228

-

 

25

-

1,151

-

1,404

 

-

 

-

 

1,404

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,619

174

 

34

230

1,239

83

3,379

 

452

 

-

 

3,831

 

 

Equity companies

39

-

 

-

-

327

-

366

 

-

 

-

 

366

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

3,313

275

 

251

1,130

4,424

190

9,583

(4)

4,560

 

581

 

14,724

 

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 62 million barrels in 2013, 46 million barrels in 2014 and 34 million barrels in 2015, as well as proved developed reserves of 55 million barrels in 2013, 36 million barrels in 2014 and 23 million barrels in 2015, and in addition, proved undeveloped reserves of 7 million barrels in 2013, 10 million barrels in 2014 and 11 million barrels in 2015, in which there is a 30.4 percent noncontrolling interest.

(2)   Includes total proved reserves attributable to Imperial Oil Limited of 2,867 million barrels in 2013, 3,274 million barrels in 2014 and 3,515 million barrels in 2015, as well as proved developed reserves of 1,417 million barrels in 2013, 1,635 million barrels in 2014 and 3,063 million barrels in 2015, and in addition, proved undeveloped reserves of 1,450 million barrels in 2013, 1,639 million barrels in 2014 and 452 million barrels in 2015, in which there is a 30.4 percent noncontrolling interest.

(3)   Includes total proved reserves attributable to Imperial Oil Limited of 579 million barrels in 2013, 534 million barrels in 2014 and 581 million barrels in 2015, as well as proved developed reserves of 579 million barrels in 2013, 534 million barrels in 2014 and 581 million barrels in 2015, 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 2015 Form 10-K.

106 


   

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, 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

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

(See footnotes on next page)

107 


   

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

South

 

 

 

Australia/

 

 

Total

 

 

States

Amer. (1)

Europe

Africa

Asia

Oceania

Total

 

All Products (2) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2015

25,987

1,226

2,383

811

5,460

7,276

43,143

 

19,013

 

 

Revisions

(6,693)

(45)

63

25

303

23

(6,324)

 

(595)

 

 

Improved recovery

-

-

-

-

-

-

-

 

2

 

 

Purchases

182

29

-

-

-

-

211

 

246

 

 

Sales

(9)

(5)

(56)

-

(89)

-

(159)

 

(39)

 

 

Extensions/discoveries

1,167

34

-

-

102

-

1,303

 

1,405

 

 

Production

(1,254)

(112)

(434)

(43)

(447)

(258)

(2,548)

 

(1,140)

 

December 31, 2015

19,380

1,127

1,956

793

5,329

7,041

35,626

 

18,892

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2015

272

-

8,418

-

17,505

-

26,195

 

6,256

 

 

Revisions

(38)

-

(83)

-

86

-

(35)

 

11

 

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

 

Purchases

1

-

-

-

-

-

1

 

-

 

 

Sales

-

-

-

-

-

-

-

 

-

 

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

 

Production

(15)

-

(432)

-

(1,130)

-

(1,577)

 

(400)

 

December 31, 2015

220

-

7,903

-

16,461

-

24,584

 

5,867

 

Total proved reserves at December 31, 2015

19,600

1,127

9,859

793

21,790

7,041

60,210

 

24,759

 

 

(1)   Includes total proved reserves attributable to Imperial Oil Limited of 678 billion cubic feet in 2013, 627 billion cubic feet in 2014 and 583 billion cubic feet in 2015, as well as proved developed reserves of 368 billion cubic feet in 2013, 300 billion cubic feet in 2014 and 283 billion cubic feet in 2015, and in addition, proved undeveloped reserves of 310 billion cubic feet in 2013, 327 billion cubic feet in 2014 and 300 billion cubic feet in 2015, 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.

108 


   

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, 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

13,353

552

1,593

750

4,917

1,962

23,127

 

12,977

 

 

 

Equity companies

156

-

6,146

-

15,233

-

21,535

 

4,993

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

6,027

575

363

43

412

5,079

12,499

 

5,915

 

 

 

Equity companies

64

-

1,757

-

1,228

-

3,049

 

874

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2015

19,600

1,127

9,859

793

21,790

7,041

60,210

 

24,759

 

 

(See footnotes on previous page)

109 


   

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, 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

 

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

110 


   

 

 

 

 

 

 

 

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, 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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

144,910

 

176,452

 

23,330

 

57,702

 

156,378

 

29,535

 

588,307

 

 

Future production costs

 

82,678

 

115,285

 

8,735

 

17,114

 

50,745

 

8,889

 

283,446

 

 

Future development costs

 

35,016

 

36,923

 

11,332

 

11,170

 

15,371

 

8,237

 

118,049

 

 

Future income tax expenses

 

5,950

 

3,042

 

1,780

 

14,018

 

62,353

 

5,012

 

92,155

 

 

Future net cash flows

 

21,266

 

21,202

 

1,483

 

15,400

 

27,909

 

7,397

 

94,657

 

 

Effect of discounting net cash flows at 10%

 

13,336

 

13,415

 

(945)

 

5,226

 

17,396

 

3,454

 

51,882

 

 

Discounted future net cash flows

 

7,930

 

7,787

 

2,428

 

10,174

 

10,513

 

3,943

 

42,775

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

13,065

 

-

 

49,061

 

-

 

143,692

 

-

 

205,818

 

 

Future production costs

 

6,137

 

-

 

35,409

 

-

 

57,080

 

-

 

98,626

 

 

Future development costs

 

2,903

 

-

 

2,190

 

-

 

12,796

 

-

 

17,889

 

 

Future income tax expenses

 

-

 

-

 

4,027

 

-

 

24,855

 

-

 

28,882

 

 

Future net cash flows

 

4,025

 

-

 

7,435

 

-

 

48,961

 

-

 

60,421

 

 

Effect of discounting net cash flows at 10%

 

1,936

 

-

 

4,287

 

-

 

26,171

 

-

 

32,394

 

 

Discounted future net cash flows

 

2,089

 

-

 

3,148

 

-

 

22,790

 

-

 

28,027

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

10,019

 

7,787

 

5,576

 

10,174

 

33,303

 

3,943

 

70,802

 

(1)   Includes discounted future net cash flows attributable to Imperial Oil Limited of $30,189 million in 2014 and $5,607 million in 2015, in which there is a 30.4 percent noncontrolling interest.

111 


   

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated and Equity Interests

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

112 


   

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

 

Consolidated and Equity Interests (continued)

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2014

 

138,664

 

 

68,921

 

 

207,585

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

5,678

 

 

-

 

 

5,678

 

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

 

(20,694)

 

 

(9,492)

 

 

(30,186)

 

 

Development costs incurred during the year

 

18,359

 

 

1,198

 

 

19,557

 

 

Net change in prices, lifting and development costs

 

(203,224)

 

 

(57,478)

 

 

(260,702)

 

 

Revisions of previous reserves estimates

 

6,888

 

 

(134)

 

 

6,754

 

 

Accretion of discount

 

17,828

 

 

7,257

 

 

25,085

 

Net change in income taxes

 

79,276

 

 

17,755

 

 

97,031

 

 

 

Total change in the standardized measure during the year

 

(95,889)

 

 

(40,894)

 

 

(136,783)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2015

 

42,775

 

 

28,027

 

 

70,802

 

 

 

 

 

 

 

 

 

 

 

 

 

113 


OPERATING SUMMARY (unaudited)

  

 

 

 

2015

 

2014

 

2013

 

2012

 

2011

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

 

 

 

 

 

 

 

 

 

 

Net production

(thousands of barrels daily)

 

 

United States

476

 

454

 

431

 

418

 

423

 

 

Canada/South America

402

 

301

 

280

 

251

 

252

 

 

Europe

204

 

184

 

190

 

207

 

270

 

 

Africa

529

 

489

 

469

 

487

 

508

 

 

Asia

684

 

624

 

784

 

772

 

808

 

 

Australia/Oceania

50

 

59

 

48

 

50

 

51

 

Worldwide

2,345

 

2,111

 

2,202

 

2,185

 

2,312

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Net production

(millions of cubic feet daily)

 

 

United States

3,147

 

3,404

 

3,545

 

3,822

 

3,917

 

 

Canada/South America

261

 

310

 

354

 

362

 

412

 

 

Europe

2,286

 

2,816

 

3,251

 

3,220

 

3,448

 

 

Africa

5

 

4

 

6

 

17

 

7

 

 

Asia

4,139

 

4,099

 

4,329

 

4,538

 

5,047

 

 

Australia/Oceania

677

 

512

 

351

 

363

 

331

 

Worldwide

10,515

 

11,145

 

11,836

 

12,322

 

13,162

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1) 

4,097

 

3,969

 

4,175

 

4,239

 

4,506

 

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

(thousands of barrels daily)

 

 

United States

1,709

 

1,809

 

1,819

 

1,816

 

1,784

 

 

Canada

386

 

394

 

426

 

435

 

430

 

 

Europe

1,496

 

1,454

 

1,400

 

1,504

 

1,528

 

 

Asia Pacific

647

 

628

 

779

 

998

 

1,180

 

 

Other Non-U.S.

194

 

191

 

161

 

261

 

292

 

Worldwide

4,432

 

4,476

 

4,585

 

5,014

 

5,214

Petroleum product sales (2) 

 

 

 

 

 

 

 

 

 

 

 

United States

2,521

 

2,655

 

2,609

 

2,569

 

2,530

 

 

Canada

488

 

496

 

464

 

453

 

455

 

 

Europe

1,542

 

1,555

 

1,497

 

1,571

 

1,596

 

 

Asia Pacific and other Eastern Hemisphere

1,124

 

1,085

 

1,206

 

1,381

 

1,556

 

 

Latin America

79

 

84

 

111

 

200

 

276

 

Worldwide

5,754

 

5,875

 

5,887

 

6,174

 

6,413

 

 

Gasoline, naphthas

2,363

 

2,452

 

2,418

 

2,489

 

2,541

 

 

Heating oils, kerosene, diesel oils

1,924

 

1,912

 

1,838

 

1,947

 

2,019

 

 

Aviation fuels

413

 

423

 

462

 

473

 

492

 

 

Heavy fuels

377

 

390

 

431

 

515

 

588

 

 

Specialty petroleum products

677

 

698

 

738

 

750

 

773

 

Worldwide

5,754

 

5,875

 

5,887

 

6,174

 

6,413

 

 

 

 

 

 

 

 

 

 

 

 

Chemical prime product sales (2)(3) 

(thousands of metric tons)

 

 

United States

9,664

 

9,528

 

9,679

 

9,381

 

9,250

 

 

Non-U.S.

15,049

 

14,707

 

14,384

 

14,776

 

15,756

 

Worldwide

24,713

 

24,235

 

24,063

 

24,157

 

25,006

 

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 and chemical prime 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.

  

 

114 


 

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 24, 2016

     

 

 

  

 

 

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Randall M. Ebner, Stephen A. Littleton and Jeffrey S. Lynn 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 24, 2016.

 

 

 

 

 

 

/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

  

115 


 

/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/    DOUGLAS R. OBERHELMAN

 

(Douglas R. Oberhelman)

 

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/    DARREN W. WOODS

 

(Darren W. Woods)

 

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)

  

116 


INDEX TO EXHIBITS

 

  

 

Exhibit

Description

 

 

3(i)

Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001.

 

 

3(ii)

By-Laws, as revised to April 27, 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 (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant’s Annual Report on Form 10-K for 2014).*

 

 

10(iii)(c.2)

ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Annual Report on Form 10-K for 2014).*

 

 

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 (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2014).*

 

 

10(iii)(f.4)

Standing resolution for non-employee director cash fees dated October 26, 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.

  

117 


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.

 

118