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EXXON MOBIL CORP - Annual Report: 2018 (Form 10-K)

 

 

 

2018  

  

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, 2018

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) 940-6000

(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 (4,234,802,431 shares outstanding at January 31, 2019)

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 every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) 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 (§ 229.405 of this chapter) 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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

Accelerated filer

 

Non-accelerated filer

Smaller reporting company

 

 

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $82.73 on the New York Stock Exchange composite tape, was in excess of $350 billion.

Documents Incorporated by Reference:  Proxy Statement for the 2019 Annual Meeting of Shareholders (Part III)

 

 

 


 

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018

TABLE OF CONTENTS

 

 

 

PART I

 

 

 

Item 1.

Business

           1  

 

 

 

Item 1A.

Risk Factors

           2  

 

 

 

Item 1B.

Unresolved Staff Comments

           5  

 

 

 

Item 2.

Properties

           6  

 

 

 

Item 3.

Legal Proceedings

         27  

 

 

 

Item 4.

Mine Safety Disclosures

         27  

 

 

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

         28  

 

PART II

 

 

 

Item 5.

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

         31  

 

 

 

Item 6.

Selected Financial Data

         31  

 

 

 

Item 7.

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

         31  

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

         31  

 

 

 

Item 8.

Financial Statements and Supplementary Data

         32  

 

 

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

         32  

 

 

 

Item 9A.

Controls and Procedures

         32  

 

 

 

Item 9B.

Other Information

         32  

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

         33  

 

 

 

Item 11.

Executive Compensation

         33  

 

 

 

Item 12.

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

         33  

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

         34  

 

 

 

Item 14.

Principal Accounting Fees and Services

         34  

 

PART IV

 

 

 

Item 15.

Exhibits, Financial Statement Schedules

         34  

 

 

 

Item 16.

Form 10-K Summary

         34  

 

 

Financial Section

         35  

 

 

Index to Exhibits

       123  

 

 

Signatures

       124  

 

 

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 involves exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals 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.

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 Information”. 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. ExxonMobil held nearly 13 thousand active patents worldwide at the end of 2018. For technology licensed to third parties, revenues totaled approximately $119 million in 2018. 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 71.0 thousand, 69.6 thousand, and 71.1 thousand at years ended 2018, 2017 and 2016, 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.

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 2018 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.9 billion, of which $3.6 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to increase to approximately $5.7 billion in 2019 and 2020. Capital expenditures are expected to account for approximately 30 percent of the total.

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 (SEC). 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.

The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

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 is generally linked closely with broad-based economic activities and levels of prosperity. 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; increased competitiveness of alternative energy sources; changes in technology or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation or increased consumer demand for alternative fueled or electric vehicles; and broad-based changes in personal income levels.

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 relative to demand 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 countries to OPEC production quotas and other agreements among sovereigns, and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, logistics constraints 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.

 

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 United States 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, or may be unable to maintain, 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 or interpretation of settled law (including changes that result from international treaties and accords) that could adversely affect our results, such as:

  

·           

increases in taxes, duties, 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, methane emissions, hydraulic fracturing or plastics);

·           

adoption of regulations mandating efficiency standards, 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, cybersecurity attacks, 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 risks 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, minimum renewable usage requirements, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. Such policies could make our products more expensive, less competitive, 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 or policies 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 and others 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 both in-house and by working with more than 80 leading universities around the world, including the Massachusetts Institute of Technology, Princeton University, The University of Texas, and Stanford University. Our research projects focus on developing algae-based biofuels, carbon capture and storage, breakthrough energy efficiency processes, advanced energy-saving materials, and other technologies. For example, ExxonMobil is working with Fuel Cell Energy Inc. to explore using carbonate fuel cells to economically capture CO2 emissions from gas-fired power plants. 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 “Operational and Other Factors” below.

 

Operational and Other Factors

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.

3 


 

Project and portfolio management. The long-term 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. In addition to the effective management of individual projects, ExxonMobil’s success, including our ability to mitigate risk and provide attractive returns to shareholders, depends on our ability to successfully manage our overall portfolio, including diversification among types and locations of our projects.

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 and technological change. 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. To remain competitive we must also continuously adapt and capture the benefits of new and emerging technologies.

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 on workplace safety and 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.

Cybersecurity. ExxonMobil is regularly subject to attempted cybersecurity disruptions from a variety of threat actors including state-sponsored actors. ExxonMobil’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions; non-technological measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness and an emphasis on resiliency including business response and recovery. If the measures we are taking to protect against cybersecurity disruptions prove to be insufficient, ExxonMobil as well as our customers, employees, or third parties could be adversely affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation or reputational harm.

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 rainfall 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.

4 


 

Insurance limitations. The ability of the Corporation to insure against many of the risks it faces as described in this Item 1A is limited by the capacity of the applicable insurance markets, which may not be sufficient.

Competition. As noted in Item 1 above, the energy and petrochemical industries are highly competitive. We face competition not only from other private firms, but also from state-owned companies that are increasingly competing for opportunities outside of their home countries. In some cases, these state-owned companies may pursue opportunities in furtherance of strategic objectives of their government owners, with less focus on financial returns than companies owned by private shareholders, such as ExxonMobil. Technology and expertise provided by industry service companies may also enhance the competitiveness of firms that may not have the internal resources and capabilities of ExxonMobil or reduce the need for resource-owning countries to partner with private-sector oil and gas companies in order to monetize national resources.

Reputation. Our reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, or other adverse event such as those described in this Item 1A may have a negative impact on our reputation, which in turn could make it more difficult for us to compete successfully for new opportunities, obtain necessary regulatory approvals, or could reduce consumer demand for our branded products. ExxonMobil’s reputation may also be harmed by events which negatively affect the image of our industry as a whole.

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.

5 


 

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 2018

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. Natural gas is converted to an oil-equivalent basis at six billion cubic feet per one million 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. No major discovery or other favorable or adverse event has occurred since December 31, 2018, that would cause a significant change in the estimated proved reserves as of that date.

 

 

 

 

 

 

 

 

 

 

 

Oil-Equivalent

 

 

 

 

 

Crude

Natural Gas

 

Synthetic

Natural

Total

 

 

 

 

 

Oil

Liquids

Bitumen

Oil

Gas

All Products

 

 

 

 

 

(million bbls)

(million bbls)

(million bbls)

(million bbls)

(billion cubic ft)

(million bbls)

Proved Reserves

 

 

 

 

 

 

 

Developed

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,257

439

-

-

12,538

3,786

 

 

 

Canada/Other Americas (1) 

144

9

3,880

466

605

4,599

 

 

 

Europe

101

22

-

-

1,116

309

 

 

 

Africa

496

82

-

-

581

675

 

 

 

Asia

2,184

101

-

-

3,618

2,888

 

 

 

Australia/Oceania

75

43

-

-

4,336

841

 

 

 

 

Total Consolidated

4,257

696

3,880

466

22,794

13,098

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

202

6

-

-

152

233

 

 

 

Europe

15

-

-

-

988

180

 

 

 

Africa

-

-

-

-

-

-

 

 

 

Asia

637

282

-

-

11,951

2,911

 

 

 

 

Total Equity Company

854

288

-

-

13,091

3,324

 

 

 

 

Total Developed

5,111

984

3,880

466

35,885

16,422

 

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

1,947

669

-

-

8,865

4,093

 

 

 

Canada/Other Americas (1) 

385

18

305

-

1,139

898

 

 

 

Europe

65

13

-

-

196

111

 

 

 

Africa

108

3

-

-

7

112

 

 

 

Asia

1,173

-

-

-

223

1,210

 

 

 

Australia/Oceania

30

5

-

-

3,126

556

 

 

 

 

Total Consolidated

3,708

708

305

-

13,556

6,980

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

52

4

-

-

73

68

 

 

 

Europe

-

-

-

-

69

12

 

 

 

Africa

6

-

-

-

863

150

 

 

 

Asia

383

50

-

-

1,370

661

 

 

 

 

Total Equity Company

441

54

-

-

2,375

891

 

 

 

 

Total Undeveloped

4,149

762

305

-

15,931

7,871

Total Proved Reserves

9,260

1,746

4,185

466

51,816

24,293

 

(1)   Other Americas includes proved developed reserves of 1 million barrels of crude oil and 99 billion cubic feet of natural gas, as well as proved undeveloped reserves of 226 million barrels of crude oil and 423 billion cubic feet of natural gas.

6 


 

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 pressures. 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, government policies, consumer preferences, and significant changes in 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.

B. Technologies Used in Establishing Proved Reserves Additions in 2018

Additions to ExxonMobil’s proved reserves in 2018 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 oil, 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 25 years of experience in reservoir engineering and reserves assessment, has a degree in Engineering and currently serves on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE). 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.

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.

7 


 

 2. Proved Undeveloped Reserves  

At year-end 2018, approximately 7.9 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 32 percent of the 24.3 GOEB reported in proved reserves. This compares to the 7.3 GOEB of proved undeveloped reserves reported at the end of 2017. During the year, ExxonMobil conducted development activities that resulted in the transfer of approximately 0.8 GOEB from proved undeveloped to proved developed reserves by year end. The largest transfers were related to drilling activity in the United States, the United Arab Emirates, Canada, and Russia. During 2018, extensions and discoveries, primarily in the United States resulted in an addition of approximately 1.7 GOEB of proved undeveloped reserves. Also, the Corporation reclassified approximately 0.3 GOEB of proved undeveloped reserves which no longer met the SEC definition of proved reserves, primarily in the Netherlands at the Groningen gas field and the United States.

Overall, investments of $13.2 billion were made by the Corporation during 2018 to progress the development of reported proved undeveloped reserves, including $13.1 billion for oil and gas producing activities and additional investments for other non-oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments represented 65 percent of the $20.2 billion in total reported Upstream capital and exploration expenditures.

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 several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. Proved undeveloped reserves in the United States, Canada, Australia, and Kazakhstan have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure, 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, government policies, consumer preferences, the pace of co‑venturer/government funding, changes in the amount and timing of capital investments, 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, over 80 percent are contained in the aforementioned countries. In Canada, proved undeveloped reserves are related to drilling activities in the offshore Hebron field and onshore Cold Lake operations. In Australia, proved undeveloped reserves are associated with future compression for the Gorgon Jansz LNG project. In Kazakhstan, the proved undeveloped reserves are related to the remainder of the initial development of the producing 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.

  

8 


 

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.



 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

 

(thousands of barrels daily)

Crude oil and natural gas liquids production

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Crude Oil

NGL

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

395

101

 

361

96

 

347

87

 

 

Canada/Other Americas (1) 

 

62

6

 

44

6

 

53

6

 

 

Europe

 

101

27

 

147

31

 

171

31

 

 

Africa

 

377

10

 

412

11

 

459

15

 

 

Asia

 

398

25

 

373

26

 

383

27

 

 

Australia/Oceania

 

31

16

 

35

19

 

37

19

 

 

 

Total Consolidated Subsidiaries

 

1,364

185

 

1,372

189

 

1,450

185

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

54

1

 

55

2

 

58

2

 

 

Europe

 

4

-

 

4

-

 

2

-

 

 

Asia

 

226

62

 

235

64

 

232

65

 

 

 

Total Equity Companies

 

284

63

 

294

66

 

292

67

 

 

 

 

 

 

 

 

 

 

 

 

 

Total crude oil and natural gas liquids production

 

1,648

248

 

1,666

255

 

1,742

252

 

 

 

 

 

 

 

 

 

 

 

 

 

Bitumen production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/Other Americas

 

310

 

 

305

 

 

304

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Synthetic oil production

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

Canada/Other Americas

 

60

 

 

57

 

 

67

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total liquids production

 

2,266

 

 

2,283

 

 

2,365

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

 

2,550

 

 

2,910

 

 

3,052

 

 

 

Canada/Other Americas (1) 

 

227

 

 

218

 

 

239

 

 

 

Europe

 

925

 

 

1,046

 

 

1,093

 

 

 

Africa

 

13

 

 

5

 

 

7

 

 

 

Asia

 

838

 

 

906

 

 

927

 

 

 

Australia/Oceania

 

1,325

 

 

1,310

 

 

887

 

 

 

 

Total Consolidated Subsidiaries

 

5,878

 

 

6,395

 

 

6,205

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

 

24

 

 

26

 

 

26

 

 

 

Europe

 

728

 

 

902

 

 

1,080

 

 

 

Asia

 

2,775

 

 

2,888

 

 

2,816

 

 

 

 

Total Equity Companies

 

3,527

 

 

3,816

 

 

3,922

 

Total natural gas production available for sale

 

9,405

 

 

10,211

 

 

10,127

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production

 

3,833

 

 

3,985

 

 

4,053

 

 

(1)   Other Americas includes crude oil production for 2018 of two thousand barrels daily and natural gas production available for sale for 2018, 2017 and 2016 of 28 million, 24 million, and 22 million cubic feet daily, respectively.

9 


 

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.

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

United

Other

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

Americas

Europe

 

Africa

 

Asia

Oceania

Total

During 2018

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

59.84

 

64.53

 

69.80

 

70.84

 

69.86

 

66.89

 

66.91

 

 

 

NGL, per barrel

 

30.78

 

37.27

 

38.53

 

47.10

 

26.30

 

36.34

 

32.88

 

 

 

Natural gas, per thousand cubic feet

 

2.14

 

1.68

 

6.97

 

1.96

 

2.33

 

6.39

 

3.87

 

 

 

Bitumen, per barrel

 

-

 

28.66

 

-

 

-

 

-

 

-

 

28.66

 

 

 

Synthetic oil, per barrel

 

-

 

54.85

 

-

 

-

 

-

 

-

 

54.85

 

 

Average production costs, per oil-equivalent barrel - total

11.64

 

24.32

 

13.07

 

17.28

 

7.31

 

6.94

 

13.34

 

 

Average production costs, per barrel - bitumen

-

 

22.93

 

-

 

-

 

-

 

-

 

22.93

 

 

Average production costs, per barrel - synthetic oil

-

 

45.33

 

-

 

-

 

-

 

-

 

45.33

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

66.30

 

-

 

63.92

 

-

 

67.31

 

-

 

67.07

 

 

 

NGL, per barrel

 

27.16

 

-

 

-

 

-

 

45.10

 

-

 

44.64

 

 

 

Natural gas, per thousand cubic feet

 

2.19

 

-

 

5.03

 

-

 

6.31

 

-

 

6.01

 

 

Average production costs, per oil-equivalent barrel - total

24.71

 

-

 

16.30

 

-

 

1.49

 

-

 

4.96

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

60.61

 

64.53

 

69.57

 

70.84

 

68.92

 

66.89

 

66.93

 

 

 

NGL, per barrel

 

30.72

 

37.27

 

38.53

 

47.10

 

39.69

 

36.34

 

35.85

 

 

 

Natural gas, per thousand cubic feet

 

2.14

 

1.68

 

6.11

 

1.96

 

5.38

 

6.39

 

4.67

 

 

 

Bitumen, per barrel

 

-

 

28.66

 

-

 

-

 

-

 

-

 

28.66

 

 

 

Synthetic oil, per barrel

 

-

 

54.85

 

-

 

-

 

-

 

-

 

54.85

 

 

Average production costs, per oil-equivalent barrel - total

12.43

 

24.32

 

14.06

 

17.31

 

3.98

 

6.94

 

11.29

 

 

Average production costs, per barrel - bitumen

-

 

22.93

 

-

 

-

 

-

 

-

 

22.93

 

 

Average production costs, per barrel - synthetic oil

-

 

45.33

 

-

 

-

 

-

 

-

 

45.33

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2017

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

46.71

 

52.42

 

52.02

 

54.70

 

53.26

 

53.61

 

51.88

 

 

 

NGL, per barrel

 

24.20

 

27.07

 

30.96

 

37.38

 

22.69

 

33.15

 

26.88

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

2.03

 

5.48

 

1.51

 

2.05

 

4.22

 

3.04

 

 

 

Bitumen, per barrel

 

-

 

29.70

 

-

 

-

 

-

 

-

 

29.70

 

 

 

Synthetic oil, per barrel

 

-

 

52.72

 

-

 

-

 

-

 

-

 

52.72

 

 

Average production costs, per oil-equivalent barrel - total

10.85

 

23.44

 

12.25

 

13.33

 

8.07

 

6.30

 

12.33

 

 

Average production costs, per barrel - bitumen

-

 

21.39

 

-

 

-

 

-

 

-

 

21.39

 

 

Average production costs, per barrel - synthetic oil

-

 

44.21

 

-

 

-

 

-

 

-

 

44.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

49.13

 

-

 

47.69

 

-

 

50.27

 

-

 

50.02

 

 

 

NGL, per barrel

 

21.78

 

-

 

-

 

-

 

38.23

 

-

 

37.81

 

 

 

Natural gas, per thousand cubic feet

 

2.42

 

-

 

4.81

 

-

 

4.15

 

-

 

4.30

 

 

Average production costs, per oil-equivalent barrel - total

23.38

 

-

 

7.45

 

-

 

1.18

 

-

 

3.51

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

47.03

 

52.42

 

51.91

 

54.70

 

52.12

 

53.61

 

51.56

 

 

 

NGL, per barrel

 

24.16

 

27.07

 

30.96

 

37.38

 

33.79

 

33.15

 

29.70

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

2.03

 

5.17

 

1.51

 

3.65

 

4.22

 

3.51

 

 

 

Bitumen, per barrel

 

-

 

29.70

 

-

 

-

 

-

 

-

 

29.70

 

 

 

Synthetic oil, per barrel

 

-

 

52.72

 

-

 

-

 

-

 

-

 

52.72

 

 

Average production costs, per oil-equivalent barrel - total

11.61

 

23.44

 

10.79

 

13.33

 

4.02

 

6.30

 

10.12

 

 

Average production costs, per barrel - bitumen

-

 

21.39

 

-

 

-

 

-

 

-

 

21.39

 

 

Average production costs, per barrel - synthetic oil

-

 

44.21

 

-

 

-

 

-

 

-

 

44.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10 


 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

United

Other

 

 

 

 

 

Australia/

 

 

 

 

 

 

States

Americas

Europe

 

Africa

 

Asia

 

Oceania

 

Total

During 2016

 

(dollars per unit)

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

36.47

 

39.50

 

40.57

 

42.59

 

41.89

 

43.33

 

40.59

 

 

 

NGL, per barrel

 

16.16

 

18.91

 

22.17

 

26.78

 

17.12

 

23.95

 

18.99

 

 

 

Natural gas, per thousand cubic feet

 

1.43

 

1.71

 

4.26

 

1.14

 

1.56

 

3.46

 

2.25

 

 

 

Bitumen, per barrel

 

-

 

19.30

 

-

 

-

 

-

 

-

 

19.30

 

 

 

Synthetic oil, per barrel

 

-

 

43.03

 

-

 

-

 

-

 

-

 

43.03

 

 

Average production costs, per oil-equivalent barrel - total

10.41

 

21.16

 

12.78

 

12.75

 

6.44

 

7.12

 

11.79

 

 

Average production costs, per barrel - bitumen

 

-

 

18.25

 

-

 

-

 

-

 

-

 

18.25

 

 

Average production costs, per barrel - synthetic oil

 

-

 

33.64

 

-

 

-

 

-

 

-

 

33.64

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

38.44

 

-

 

36.13

 

-

 

39.69

 

-

 

39.41

 

 

 

NGL, per barrel

 

14.85

 

-

 

-

 

-

 

25.21

 

-

 

24.87

 

 

 

Natural gas, per thousand cubic feet

 

2.03

 

-

 

4.19

 

-

 

3.59

 

-

 

3.75

 

 

Average production costs, per oil-equivalent barrel - total

22.26

 

-

 

7.92

 

-

 

1.80

 

-

 

4.21

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average production prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil, per barrel

 

36.75

 

39.50

 

40.51

 

42.59

 

41.06

 

43.33

 

40.39

 

 

 

NGL, per barrel

 

16.13

 

18.91

 

22.17

 

26.78

 

22.85

 

23.95

 

20.56

 

 

 

Natural gas, per thousand cubic feet

 

1.44

 

1.71

 

4.22

 

1.14

 

3.09

 

3.46

 

2.83

 

 

 

Bitumen, per barrel

 

-

 

19.30

 

-

 

-

 

-

 

-

 

19.30

 

 

 

Synthetic oil, per barrel

 

-

 

43.03

 

-

 

-

 

-

 

-

 

43.03

 

 

Average production costs, per oil-equivalent barrel - total

11.18

 

21.16

 

11.21

 

12.75

 

3.77

 

7.12

 

9.89

 

 

Average production costs, per barrel - bitumen

 

-

 

18.25

 

-

 

-

 

-

 

-

 

18.25

 

 

Average production costs, per barrel - synthetic oil

 

-

 

33.64

 

-

 

-

 

-

 

-

 

33.64

 

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

11 


 

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled



 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

Net Productive Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

1

 

-

 

-

 

 

Canada/Other Americas

 

4

 

5

 

2

 

 

Europe

 

-

 

-

 

1

 

 

Africa

 

1

 

1

 

1

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

1

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

7

 

6

 

4

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

-

 

1

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

-

 

-

 

1

Total productive exploratory wells drilled

 

7

 

6

 

5

 

 

 

 

 

 

 

 

 

 

Net Dry Exploratory Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

3

 

-

 

-

 

 

Canada/Other Americas

 

-

 

-

 

1

 

 

Europe

 

1

 

-

 

-

 

 

Africa

 

-

 

2

 

1

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

2

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

6

 

2

 

2

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

-

 

-

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

1

 

-

 

 

 

Total Equity Companies

 

-

 

1

 

-

Total dry exploratory wells drilled

 

6

 

3

 

2

12 


 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

Net Productive Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

389

 

300

 

335

 

 

Canada/Other Americas

 

32

 

12

 

13

 

 

Europe

 

3

 

6

 

9

 

 

Africa

 

1

 

6

 

7

 

 

Asia

 

14

 

15

 

13

 

 

Australia/Oceania

 

-

 

1

 

-

 

 

 

Total Consolidated Subsidiaries

 

439

 

340

 

377

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

168

 

154

 

121

 

 

Europe

 

3

 

1

 

2

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

6

 

3

 

3

 

 

 

Total Equity Companies

 

177

 

158

 

126

Total productive development wells drilled

 

616

 

498

 

503

 

 

 

 

 

 

 

 

 

 

Net Dry Development Wells Drilled

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

United States

 

4

 

4

 

2

 

 

Canada/Other Americas

 

1

 

-

 

-

 

 

Europe

 

-

 

1

 

2

 

 

Africa

 

1

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

Australia/Oceania

 

-

 

-

 

-

 

 

 

Total Consolidated Subsidiaries

 

6

 

5

 

4

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

United States

 

-

 

-

 

-

 

 

Europe

 

-

 

-

 

-

 

 

Africa

 

-

 

-

 

-

 

 

Asia

 

-

 

-

 

-

 

 

 

Total Equity Companies

 

-

 

-

 

-

Total dry development wells drilled

 

6

 

5

 

4

 

 

 

 

 

 

 

 

 

 

 

Total number of net wells drilled

 

635

 

512

 

514

13 


 

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 2018, the company’s share of net production of synthetic crude oil was about 60 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl 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 about 49 thousand acres in the Athabasca oil sands deposit.

Kearl is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Bitumen is extracted from oil sands 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 2018, average net production at Kearl was about 191 thousand barrels per day.

At year-end 2018, an additional 3.4 billion barrels of bitumen at Kearl qualified as proved reserves under the SEC definition requiring calculations based on the average of the first-day-of-the-month price during the last 12-month period.

 

5. Present Activities

A. Wells Drilling

 

 

 

 

 

Year-End 2018

 

Year-End 2017

 

 

 

 

Gross

 

Net

 

Gross

 

Net

Wells Drilling

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

997

 

491

 

820

 

334

 

 

Canada/Other Americas

41

 

32

 

30

 

22

 

 

Europe

13

 

3

 

12

 

2

 

 

Africa

5

 

1

 

10

 

2

 

 

Asia

50

 

14

 

58

 

15

 

 

Australia/Oceania

4

 

2

 

3

 

1

 

 

 

Total Consolidated Subsidiaries

1,110

 

543

 

933

 

376

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

7

 

1

 

10

 

1

 

 

Europe

1

 

1

 

8

 

3

 

 

Asia

17

 

4

 

14

 

4

 

 

 

Total Equity Companies

25

 

6

 

32

 

8

Total gross and net wells drilling

1,135

 

549

 

965

 

384

14 


 

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2018 acreage holdings totaled 12.1 million net acres, of which 0.8 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During the year, 554.6 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. In addition, gas development activities continued in the Marcellus Shale of Pennsylvania and West Virginia, the Utica Shale of Ohio and the Haynesville Shale of East Texas and Louisiana.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2018 was 0.7 million acres. A total of 3.5 net exploration and development wells were completed during the year.

Participation in Alaska production and development continued with a total of 7.3 net development wells completed.

CANADA / OTHER AMERICAS  

Canada

Oil and Gas Operations:  ExxonMobil’s year-end 2018 acreage holdings totaled 6.9 million net acres, of which 3.6 million net acres were offshore. A total of 20.3 net development wells were completed during the year.

In Situ Bitumen Operations:  ExxonMobil’s year-end 2018 in situ bitumen acreage holdings totaled 0.7 million net onshore acres. A total of 10 net development wells at Cold Lake were completed during the year. 

Argentina

ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end 2018, and there were 3.6 net exploration and development wells completed during the year.

Guyana

ExxonMobil’s net acreage totaled 4.7 million offshore acres at year-end 2018, and there were 2.8 net exploration wells completed during the year. Development activities continued on the Liza Phase 1 project.

EUROPE

Germany

A total of 2.3 million net onshore acres were held by ExxonMobil at year-end 2018, with 0.1 net development well completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.4 million acres at year-end 2018, of which 1.1 million acres were onshore. A total of 2.9 net exploration and development wells were completed during the year. In 2018, the Dutch Cabinet notified Parliament of its intention to further reduce previously legislated Groningen gas extraction in response to seismic events over the last several years. Affiliates of the Corporation and their partners have actively been in discussions with the government on the associated implementation measures which resulted in a signed Heads of Agreement and the execution of additional implementation agreements. 

Norway

ExxonMobil’s net interest in licenses at year-end 2018 totaled approximately 0.1 million acres, all offshore. A total of 2.7 net development wells were completed in 2018.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2018 totaled approximately 0.6 million acres, all offshore. A total of 0.6 net development wells were completed during the year.  Development activities continued on the Penguins Redevelopment project.  

 

 

15 


 

AFRICA

Angola

ExxonMobil’s net acreage totaled 0.2 million offshore acres at year-end 2018, with 2.0 net exploration and development wells completed during the year. On Block 32, development activities continued on the Kaombo Split Hub project as the Norte floating production storage and offloading (FPSO) vessel started up in 2018 and construction progressed on the Sul FPSO.  

Chad

At year-end 2018, ExxonMobil’s net acreage holdings totaled 46 thousand onshore acres.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.5 million net offshore acres at year-end 2018, with 0.8 net development well completed during the year. In 2018, ExxonMobil acquired deepwater acreage in Block EG-11.

Mozambique

ExxonMobil’s net acreage totaled approximately 2.6 million offshore acres at year-end 2018. ExxonMobil acquired an interest in offshore blocks Angoche A5-B, Zambezi Z5-C, and Zambezi Z5-D in December 2018. Development activities continued on the Coral South Floating LNG project during 2018.

Nigeria

ExxonMobil’s net acreage totaled 0.8 million offshore acres at year-end 2018, with 0.2 net development well completed during the year. In 2018, ExxonMobil relinquished approximately 0.3 million net acres offshore.

ASIA

Azerbaijan

At year-end 2018, ExxonMobil's net acreage totaled 7 thousand offshore acres. A total of 1.0 net development wells were completed during the year. The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field was amended in September 2017 to extend the term by 25 years to 2049.

Indonesia

At year-end 2018, ExxonMobil had 0.1 million net acres onshore. The Kedung Keris project was funded in 2018.

Iraq

At year-end 2018, ExxonMobil’s onshore acreage was 0.1 million net acres. A total of 1.7 net development wells were completed at the West Qurna Phase I oil field during the year. Oil field rehabilitation activities continued during 2018 and across the life of this project will include drilling of new wells, working over of existing wells, and optimization and debottlenecking of existing facilities. In the Kurdistan Region of Iraq, ExxonMobil has continued exploration activities.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2018. A total of 7.2 net development wells were completed during 2018. Development activities continued on the Tengiz Expansion project.

Malaysia

ExxonMobil’s interests in production sharing contracts covered 2.4 million net acres offshore at year-end 2018. During the year, a total of 0.5 net development well was completed. 

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2018. 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 in 2018.

16 


 

Russia

ExxonMobil’s net acreage holdings in Sakhalin at year-end 2018 were 85 thousand acres, all offshore. A total of 3.0 net development wells were completed.

ExxonMobil withdrew from the joint ventures with Rosneft for the Kara, Laptev, Chukchi and Black Seas and western Siberia, effective April 30, 2018. ExxonMobil continues to remain in compliance with all laws applicable to its operations and investments in the Russian Federation.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2018.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2018. A total of 6.7 net development wells were completed. During 2018, development activities continued on the Upper Zakum 750 project, and work progressed on the Upper Zakum 1MBD project. 

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s net acreage totaled 1.9 million acres offshore and 31 thousand acres onshore at year-end 2018. A total of 2.0 net exploration wells were completed during the year in the Bass Strait. The West Barracouta project was funded in 2018.

The co-venturer-operated Gorgon Jansz liquefied natural gas development consists of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million tonnes per year liquefied natural gas facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia. The Gorgon Stage Two project was funded in 2018.

Papua New Guinea

A total of 9.9 million net acres were held by ExxonMobil at year-end 2018, of which 5.4 million net acres were offshore. A total of 0.5 net exploration well was completed during the year. The Papua New Guinea (PNG) liquefied natural gas 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 liquefied natural gas facility near Port Moresby. During 2018, operations were temporarily interrupted following a magnitude 7.5 earthquake.

WORLDWIDE EXPLORATION

At year-end 2018, 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 28.4 million net acres were held at year-end 2018 and 1.4 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 57 million barrels of oil and 2,400 billion cubic feet of natural gas for the period from 2019 through 2021. 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.

17 


 

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

A. Gross and Net Productive Wells



 

 

 

 

 

Year-End 2018

 

Year-End 2017

 

 

 

 

Oil

Gas

 

Oil

Gas

 

 

 

 

Gross

Net

Gross

Net

 

Gross

Net

Gross

Net

Gross and Net Productive Wells

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

United States

20,996

8,460

25,061

14,396

 

20,679

8,366

27,700

15,979

 

 

Canada/Other Americas

5,037

4,781

4,262

1,650

 

4,877

4,618

4,273

1,646

 

 

Europe

981

256

648

261

 

1,016

267

664

268

 

 

Africa

1,221

472

12

5

 

1,222

474

15

6

 

 

Asia

891

286

133

79

 

900

299

139

82

 

 

Australia/Oceania

577

123

81

33

 

588

129

73

30

 

 

 

Total Consolidated Subsidiaries

29,703

14,378

30,197

16,424

 

29,282

14,153

32,864

18,011

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

United States

13,126

5,398

4,503

577

 

13,796

5,247

4,227

491

 

 

Europe

57

20

602

187

 

59

21

617

195

 

 

Asia

164

41

126

30

 

144

36

125

30

 

 

 

Total Equity Companies

13,347

5,459

5,231

794

 

13,999

5,304

4,969

716

Total gross and net productive wells

43,050

19,837

35,428

17,218

 

43,281

19,457

37,833

18,727

 

There were 28,847 gross and 24,696 net operated wells at year‑end 2018 and 30,263 gross and 25,827 net operated wells at year-end 2017. The number of wells with multiple completions was 947 gross in 2018 and 1,366 gross in 2017.

  

18 


 

B. Gross and Net Developed Acreage   

 

 

 

 

 

Year-End 2018

 

Year-End 2017

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Developed Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

13,900

 

8,399

 

14,836

 

9,026

 

 

Canada/Other Americas (1) 

3,596

 

2,325

 

3,604

 

2,328

 

 

Europe

2,937

 

1,315

 

2,970

 

1,335

 

 

Africa

2,492

 

866

 

2,492

 

866

 

 

Asia

1,939

 

563

 

1,983

 

586

 

 

Australia/Oceania

3,262

 

1,068

 

3,262

 

1,068

 

 

 

Total Consolidated Subsidiaries

28,126

 

14,536

 

29,147

 

15,209

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

929

 

208

 

930

 

208

 

 

Europe

4,110

 

1,287

 

4,170

 

1,317

 

 

Asia

628

 

155

 

628

 

155

 

 

 

Total Equity Companies

5,667

 

1,650

 

5,728

 

1,680

Total gross and net developed acreage

33,793

 

16,186

 

34,875

 

16,889

(1)   Includes developed acreage in Other Americas of 375 gross and 244 net thousands of acres for 2018 and 375 gross and 244 net thousands of acres for 2017.

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 2018

 

Year-End 2017

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

(thousands of acres)

Gross and Net Undeveloped Acreage

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

United States

7,421

 

3,427

 

7,506

 

3,489

 

 

Canada/Other Americas (1) 

34,932

 

15,340

 

29,495

 

13,410

 

 

Europe

9,168

 

4,191

 

7,576

 

3,622

 

 

Africa

44,556

 

24,000

 

37,699

 

26,705

 

 

Asia

7,195

 

2,964

 

5,802

 

2,680

 

 

Australia/Oceania

15,337

 

10,756

 

15,976

 

11,125

 

 

 

Total Consolidated Subsidiaries

118,609

 

60,678

 

104,054

 

61,031

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

United States

203

 

76

 

207

 

77

 

 

Europe

100

 

25

 

100

 

25

 

 

Africa

596

 

149

 

596

 

149

 

 

Asia

73

 

5

 

191,147

 

63,633

 

 

 

Total Equity Companies

972

 

255

 

192,050

 

63,884

Total gross and net undeveloped acreage

119,581

 

60,933

 

296,104

 

124,915

(1)   Includes undeveloped acreage in Other Americas of 23,872 gross and 9,595 net thousands of acres for 2018 and 18,625 gross and 8,053 net thousands of acres for 2017.

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.

19 


 

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 the underlying mineral interests are owned outright.

CANADA / OTHER AMERICAS

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 proven production capability 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. Offshore production licenses 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.

Guyana

The Petroleum (Exploration and Production) Act authorizes the government of Guyana to grant petroleum prospecting and production licenses and to enter into petroleum agreements for the exploration and production of hydrocarbons. Petroleum agreements provide for an exploration period of up to 10 years with a production period of 20 years with a 10 year extension.

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 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.

20 


 

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 majority of traditional licenses currently issued have an initial exploration term of four years with a second term extension of four years, and a final production 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.

Terms for exploration acreage in technically challenged areas are governed by frontier production licenses, generally covering a larger initial area than traditional licenses, with an initial exploration term of six or nine years with a second term extension of six years, and a final production term of 18 years, with relinquishment of 75 percent of the original area after three years and 50 percent of the remaining acreage after the next three years. Innovate licenses issued replace traditional and frontier licenses and offer greater flexibility with respect to periods and work program commitments.

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 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 30 years and in 2017 was extended by 20 years to 2050.

Equatorial Guinea

Exploration, development and production activities are governed by production sharing contracts (PSCs) negotiated with the State Ministry of Mines and Hydrocarbons. A new PSC was ratified in 2018; 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.

Mozambique

Exploration and production activities are generally governed by concession contracts with the Government of the Republic of Mozambique, represented by the Ministry of Mineral Resources and Energy. An interest in Area 4 offshore Mozambique was acquired in 2017. Terms for Area 4 are governed by the Exploration and Production Concession Contract (EPCC) for Area 4 Offshore of the Rovuma Block. The EPCC expires 30 years after the approval of a plan of development for a given discovery area.

In 2018 an interest was acquired in offshore blocks, A5-B, Z5-C and Z5-D. Terms for the three blocks are governed by their respective EPCCs, which have an initial exploration phase that expires in 2022 with the possibility of two additional exploration phases expiring in 2024 and 2025. The EPCCs provide a development and production period that expires 30 years after the approval of a plan of development.

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 10 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.

 

 

21 


 

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 10 years of their duration.

ASIA

Azerbaijan

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field was established for an initial period of 30 years starting from the PSA execution date in 1994. The PSA was amended in September 2017 to extend the term by 25 years to 2049.

Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period typically 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 Basra 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. Current PSCs remain in effect by agreement of the regional government to allow additional time for exploration or evaluation of commerciality. 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 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 exploration and production terms ranging up to 38 years. All extensions are subject to the national oil company’s prior written approval. The production periods range from 15 to 29 years, depending on the provisions of the respective contract.

22 


 

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.

Russia

Terms for ExxonMobil’s Sakhalin acreage are fixed by the current production sharing agreement (PSA) between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator.

ExxonMobil withdrew from the joint ventures with Rosneft for the Kara, Laptev, Chukchi and Black Seas, effective April 30, 2018. ExxonMobil continues to remain in compliance with all laws applicable to its operations and investments in the Russian Federation.

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. The term of the concession expires in 2021.

United Arab Emirates

An interest in the development and production activities of the Upper Zakum field, a major offshore field, was acquired in 2006. In 2017 the governing agreements were extended to 2051.

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.

23 


 

Information with regard to the Downstream segment follows:

ExxonMobil’s Downstream segment manufactures, trades 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 2018 (1)

 

 

 

 

ExxonMobil

ExxonMobil

 

 

 

 

Share  KBD (2) 

Interest %

United States

 

 

 

 

 

 

Joliet

Illinois

236

 

100

 

 

Baton Rouge

Louisiana

503

 

100

 

 

Billings

Montana

60

 

100

 

 

Baytown

Texas

561

 

100

 

 

Beaumont

Texas

369

 

100

 

 

 

 Total United States

 

1,729

 

 

 

 

 

 

 

 

 

 

 

Canada

 

 

 

 

 

 

Strathcona

Alberta

191

 

69.6

 

 

Nanticoke

Ontario

113

 

69.6

 

 

Sarnia

Ontario

119

 

69.6

 

 

 

Total Canada

 

423

 

 

 

 

 

 

 

 

 

 

 

Europe

 

 

 

 

 

 

Antwerp

Belgium

307

 

100

 

 

Fos-sur-Mer

France

133

 

82.9

 

 

Gravenchon

France

240

 

82.9

 

 

Karlsruhe

Germany

78

 

25

 

 

Trecate

Italy

132

 

74.8

 

 

Rotterdam

Netherlands

192

 

100

 

 

Slagen

Norway

116

 

100

 

 

Fawley

United Kingdom

262

 

100

 

 

 

Total Europe

 

1,460

 

 

 

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

 

 

Altona

Australia

86

 

100

 

 

Fujian

China

67

 

25

 

 

Jurong/PAC

Singapore

592

 

100

 

 

Sriracha

Thailand

167

 

66

 

 

 

Total Asia Pacific

 

912

 

 

 

 

 

 

 

 

 

 

 

Middle East

 

 

 

 

 

 

Yanbu

Saudi Arabia

200

 

50

 

 

 

 

 

 

 

 

 

Total Worldwide

 

4,724

 

 

 

 

(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 refining capacity for a minor interest held through equity securities in 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.

24 


 

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

 

Retail Sites At Year-End 2018

 

United States

 

 

 

 

Owned/leased

-

 

 

 

Distributors/resellers

10,760

 

 

 

 

Total United States

10,760

 

 

 

 

 

 

 

 

Canada

 

 

 

 

Owned/leased

-

 

 

 

Distributors/resellers

2,035

 

 

 

 

Total Canada

2,035

 

 

 

 

 

 

 

 

Europe

 

 

 

 

Owned/leased

197

 

 

 

Distributors/resellers

5,636

 

 

 

 

Total Europe

5,833

 

 

 

 

 

 

 

 

Asia Pacific

 

 

 

 

Owned/leased

580

 

 

 

Distributors/resellers

1,013

 

 

 

 

Total Asia Pacific

1,593

 

 

 

 

 

 

 

 

Latin America

 

 

 

 

Owned/leased

-

 

 

 

Distributors/resellers

177

 

 

 

 

Total Latin America

177

 

 

 

 

 

 

 

 

Middle East/Africa

 

 

 

 

Owned/leased

225

 

 

 

Distributors/resellers

183

 

 

 

 

Total Middle East/Africa

408

 

 

 

 

 

 

 

 

Worldwide

 

 

 

 

Owned/leased

1,002

 

 

 

Distributors/resellers

19,804

 

 

 

 

Total Worldwide

20,806

 

25 


 

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 2018 (1)(2)  

 

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil

 

 

 

 

Ethylene

Polyethylene

Polypropylene

Paraxylene

Interest %

North America

 

 

 

 

 

 

 

 

 

 

 

 

Baton Rouge

Louisiana

1.1

 

1.3

 

0.4

 

-

 

100

 

 

Baytown

Texas

3.8

 

-

 

0.7

 

0.6

 

100

 

 

Beaumont

Texas

0.9

 

1.0

 

-

 

0.3

 

100

 

 

Mont Belvieu

Texas

-

 

2.3

 

-

 

-

 

100

 

 

Sarnia

Ontario

0.3

 

0.5

 

-

 

-

 

69.6

 

 

 

Total North America

 

6.1

 

5.1

 

1.1

 

0.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

1.8

 

100

 

 

Sriracha

Thailand

-

 

-

 

-

 

0.5

 

66

 

 

 

Total Asia Pacific

 

2.2

 

2.1

 

1.1

 

2.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Worldwide

 

10.7

 

9.9

 

2.7

 

4.1

 

 

 

 

(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.

  

26 


 

Item 3.        Legal Proceedings

In a matter reported in the Corporation’s Form 10-Q for the second quarter of 2018, the State of Ohio Department of Natural Resources, Division of Oil & Gas Resources Management (ODNR) and XTO Energy Inc. (XTO) signed a Compliance Agreement on December 21, 2018, regarding alleged violations by XTO of the Ohio Revised Code, Ohio Administrative Code, and implementing regulations arising out of the Schnegg well incident in Belmont County, Ohio, in early 2018. The Compliance Agreement settles the following alleged actions of XTO: (1) causing brine to be discharged and contact the ground and/or surface water; (2) failure to place cement in the casing string per Ohio codes; (3) allowing a well to flow gas uncontrolled; (4) failure to construct, drill and operate a well in the manner as permitted and planned; and (5) failure to notify the ODNR upon discovery a well had sustained annular pressure above the prescribed pressure. The penalty assessment was $850,000, half paid to the ODNR on January 15, 2019, and half to be paid to 29 agencies located in Belmont County as designated by the ODNR.

In another matter relating to the Schnegg well incident, reported in the Corporation’s Form 10-Q for the second quarter of 2018, the State of Ohio Environmental Protection Agency (OEPA) and XTO signed Final Findings and Orders on December 28, 2018, regarding OEPA allegations that XTO violated the Ohio Revised Code and implementing regulations, including but not limited to: (1) failure to maintain and operate its facility in a manner using good pollution control practices; (2) failure to provide a malfunction report; (3) failure to complete and properly report quarterly inspections; and (4) failure to submit site-specific work practice plans within applicable time limits. The penalty assessment of $150,000 was paid on January 21, 2019, half to the OEPA and half to a Supplemental Environmental Project.

As reported in the Corporation’s Form 10-Q for the first quarter of 2018, the Corporation received a proposed agreed order from the Texas Commission on Environmental Quality (TCEQ), dated March 15, 2018, related to routine Title V air operating permit investigations conducted by the TCEQ in 2017 of the Baytown Refinery in Texas. The proposed agreed order alleged that the refinery failed to authorize, monitor, or keep records on certain equipment and to comply with certain flare or fuel gas monitoring system availability requirements or concentration limits. After receipt of additional information from ExxonMobil and further evaluation of the alleged violations, the TCEQ has issued a revised proposed agreed order, reducing the number of alleged violations and agreeing to an administrative penalty of $56,596 in settlement of these matters. The Agreed Order was signed by ExxonMobil on December 18, 2018, and ExxonMobil paid $28,298 on January 10, 2019. The balance will be paid to a Supplemental Environmental Project upon endorsement by the TCEQ.

As last reported in the Corporation’s Form 10-Q for the third quarter of 2018, on July 20, 2017, the United States Department of Treasury, Office of Foreign Assets Control (OFAC) assessed a civil penalty against Exxon Mobil Corporation, ExxonMobil Development Company and ExxonMobil Oil Corporation for violating the Ukraine-Related Sanctions Regulations, 31 C.F.R. part 589. The assessed civil penalty is in the amount of $2,000,000. ExxonMobil and its affiliates have been and continue to be in compliance with all sanctions and disagree that any violation has occurred. ExxonMobil and its affiliates filed a complaint on July 20, 2017, in the United States Federal District Court, Northern District of Texas seeking judicial review of, and to enjoin, the civil penalty under the Administrative Procedures Act and the United States Constitution, including on the basis that it represents an arbitrary and capricious action by OFAC and a violation of the Company’s due process rights.

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.

 

 

_______________________

 

   

27 


 

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

(positions and ages as of February 27, 2019)

 

Darren W. Woods

Chairman of the Board

 

 

 

 

Held current title since:

January 1, 2017

Age: 54

Mr. Darren W. Woods 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, and Chairman of the Board and Chief Executive Officer on January 1, 2017, positions he continues to hold as of this filing date.

 

 

 

Neil A. Chapman

Senior Vice President

 

 

 

 

Held current title since:

January 1, 2018

Age: 56

Mr. Neil A. Chapman was Senior Vice President, ExxonMobil Chemical Company April 1, 2011 – December 31, 2014. He was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation January 1, 2015 – December 31, 2017. He became Senior Vice President of Exxon Mobil Corporation on January 1, 2018, a position he continues to hold as of this filing date.

 

 

 

Andrew P. Swiger

Senior Vice President

 

 

 

 

Held current title since:

April 1, 2009

Age: 62

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

 

 

 

Jack P. Williams, Jr.

Senior Vice President

 

 

 

 

Held current title since:

June 1, 2014

Age: 55

Mr. Jack P. Williams, Jr. 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 continues to hold as of this filing date.

 

 

 

Peter P. Clarke

Vice President

 

 

 

 

Held current title since:

March 1, 2018

Age: 53

Mr. Peter P. Clarke was Business Planning & Analysis Manager, ExxonMobil Gas & Power Marketing Company May 1, 2011 – April 30, 2014. He was Vice President, Asia Pacific, Africa & Power, ExxonMobil Gas & Power Marketing Company May 1, 2014 – February 28, 2015. He was Vice President, Asia Pacific, Africa, & Americas, ExxonMobil Gas & Power Marketing Company March 1, 2015 – June 30, 2015. He was Vice President, International Gas for ExxonMobil Gas & Power Marketing Company July 1, 2015 – February 28, 2018. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on March 1, 2018, positions he continues to hold as of this filing date.

 

Bradley W. Corson

Vice President

 

 

 

 

Held current title since:

March 1, 2015

Age: 57

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 continues to hold as of this filing date.

 

 

 

 

28 


 

Neil W. Duffin

Vice President

 

 

 

 

Held current title since:

January 1, 2017

Age: 62

Mr. Neil W. Duffin was President of ExxonMobil Development Company April 13, 2007 – December 31, 2016. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on January 1, 2017, positions he continues to hold as of this filing date.

 

 

 

Randall M. Ebner

Vice President and General Counsel

 

 

 

 

Held current title since:

November 1, 2016

Age: 63

Mr. Randall M. Ebner was Assistant General Counsel of Exxon Mobil Corporation January 1, 2009 – October 31, 2016. He became Vice President and General Counsel of Exxon Mobil Corporation on November 1, 2016, positions he continues to hold as of this filing date.

 

 

 

Stephen M. Greenlee

Vice President

 

 

 

 

Held current title since:

September 1, 2010

Age: 61

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

 

 

 

Neil A. Hansen

Vice President – Investor Relations and Secretary

 

 

 

 

Held current title since:

July 1, 2018

Age: 44

Mr. Neil A. Hansen was Affiliate Finance Manager, Treasurer’s, Exxon Mobil Corporation May 1, 2013 – June 30, 2014. He was Thailand Lead Country Manager and Business Services Manager, Esso (Thailand) Public Company Ltd. July 1, 2014 – March 31, 2017. He was Controller, ExxonMobil Fuels, Lubricants & Specialties Marketing Company April 1, 2017 – December 31, 2017. He was Value Chain Controller, ExxonMobil Fuels & Lubricants Company January 1, 2018 – June 30, 2018. He became Vice President – Investor Relations and Secretary of Exxon Mobil Corporation on July 1, 2018, positions he continues to hold as of this filing date.

 

 

 

Liam M. Mallon

President, ExxonMobil Development Company

 

 

 

 

Held current title since:

January 1, 2017

Age: 56

Mr. Liam M. Mallon was Vice President, Africa, ExxonMobil Production Company June 1, 2012 – January 31, 2014. He was Executive Vice President, ExxonMobil Development Company February 1, 2014 – December 31, 2016. He became President of ExxonMobil Development Company on January 1, 2017, a position he continues to hold as of this filing date.

 

 

 

Bryan W. Milton

Vice President

 

 

 

 

Held current title since:

August 1, 2016

Age: 54

Mr. Bryan W. Milton was President of ExxonMobil Global Services Company April 1, 2011 – July 31, 2016. He was President of ExxonMobil Fuels, Lubricants & Specialties Marketing Company and Vice President of Exxon Mobil Corporation August 1, 2016 – December 31, 2017. He became President of ExxonMobil Fuels & Lubricants Company and Vice President of Exxon Mobil Corporation on January 1, 2018, positions he continues to hold as of this filing date.

 

 

 

Sara N. Ortwein

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

 

 

 

 

Held current title since:

November 1, 2016

Age: 60

Ms. Sara N. Ortwein was President of ExxonMobil Upstream Research Company September 1, 2010 – October 31, 2016. She became President of XTO Energy Inc. on November 1, 2016, a position she continues to hold as of this filing date.

 

 

 

David S. Rosenthal

Vice President and Controller

 

 

 

 

Held current title since:

October 1, 2008 (Vice President)

September 1, 2014 (Controller)

 

Age: 62

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 continues to hold as of this filing date.

 

 

29 


 

Robert N. Schleckser

Vice President and Treasurer

 

 

 

 

Held current title since:

May 1, 2011

Age: 62

Mr. Robert N. Schleckser became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, positions he continues to hold as of this filing date.

 

 

 

James M. Spellings, Jr.

Vice President and General Tax Counsel

 

 

 

 

Held current title since:

March 1, 2010

Age: 57

Mr. James M. Spellings, Jr. became Vice President and General Tax Counsel of Exxon Mobil Corporation on March 1, 2010, positions he continues to hold as of this filing date.

 

 

 

John R. Verity

Vice President

 

 

 

 

Held current title since:

January 1, 2018

Age: 60

Mr. John R. Verity was Vice President, Polyolefins, ExxonMobil Chemical Company October 17, 2008 – March 31, 2014. He was Vice President, Plastics & Resins, ExxonMobil Chemical Company April 1, 2014 – December 31, 2014. He was Senior Vice President, Polymers, ExxonMobil Chemical Company January 1, 2015 – December 31, 2017. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on January 1, 2018, positions he continues to hold as of this filing date.

 

 

 

Theodore J. Wojnar, Jr.

Vice President – Corporate Strategic Planning

 

 

 

 

Held current title since:

August 1, 2017

Age: 59

Mr. Theodore J. Wojnar, Jr. was President of ExxonMobil Research and Engineering Company April 1, 2011 – July 31, 2017. He became Vice President – Corporate Strategic Planning of Exxon Mobil Corporation on August 1, 2017, a position he continues to hold 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.

30 


 

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 and Item 12 in Part III of this report.

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2018

 

 

 

 

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 2018

-

 

-

 

November 2018

-

 

-

 

December 2018

-

 

-

 

 

Total

-

 

-

(See Note 1)

 

During the fourth quarter, the Corporation did not purchase any shares of its common stock for the treasury, and did not issue or sell any unregistered equity securities.

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 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 had suspended making purchases to reduce shares outstanding effective beginning the first quarter of 2016.

 

Item 6.        Selected Financial Data

 

 

 

Years Ended December 31,

 

 

2018

 

2017

 

2016

 

2015

 

2014

 

 

(millions of dollars, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue

 

279,332

 

237,162

 

200,628

 

239,854

 

367,647

Net income attributable to ExxonMobil

 

20,840

 

19,710

 

7,840

 

16,150

 

32,520

Earnings per common share

 

4.88

 

4.63

 

1.88

 

3.85

 

7.60

Earnings per common share - assuming dilution

 

4.88

 

4.63

 

1.88

 

3.85

 

7.60

Cash dividends per common share

 

3.23

 

3.06

 

2.98

 

2.88

 

2.70

Total assets

 

346,196

 

348,691

 

330,314

 

336,758

 

349,493

Long-term debt

 

20,538

 

24,406

 

28,932

 

19,925

 

11,653

 

 

 

 

 

 

 

 

 

 

 

 

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.

31 


 

Item 8.        Financial Statements and Supplementary Data

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

·           

Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 27, 2019, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 19: Income 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, 2018. 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, 2018.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2018, 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.

32 


 

PART III

Item 10.      Directors, Executive Officers and Corporate Governance

Reference is made to the section of this report titled “Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]”.

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2019 annual meeting of shareholders (the “2019 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”, “Board Succession” and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance” and

·           

The “Audit Committee” portion, “Director Independence” portion and the membership table of the portions entitled “Board Meetings and Annual Meeting Attendance” and “Board Committees” 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”, “Executive Compensation Tables” and “Pay Ratio” of the registrant’s 2019 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 2019 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

39,847,820

(1)

 

-

 

82,918,471

(2)(3)

 

 

 

 

 

 

 

 

 

Equity compensation plans not approved by security holders

-

 

 

-

 

-

 

 

 

 

 

 

 

 

 

 

 

Total

39,847,820

 

 

-

 

82,918,471

 

 

(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 82,444,271 shares available for award under the 2003 Incentive Program and 474,200 shares available for award under the 2004 Non‑Employee Director Restricted Stock Plan.

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

33 


 

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 2019 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 2019 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.

 

Item 16.      FORM 10-K SUMMARY

None.

34 


 

FINANCIAL SECTION

 

 

TABLE OF CONTENTS

 

 

 

Business Profile

36

 

 

Financial Information

37

 

 

Frequently Used Terms

38

 

 

Quarterly Information

40

 

 

Management’s Discussion and Analysis of Financial Condition

and Results of Operations

 

 

 

Functional Earnings

41

 

 

Forward-Looking Statements

41

 

 

Overview

41

 

 

Business Environment and Risk Assessment

42

 

 

Review of 2018 and 2017 Results

46

 

 

Liquidity and Capital Resources

50

 

 

Capital and Exploration Expenditures

54

 

 

Taxes

55

 

 

Environmental Matters

56

 

 

Market Risks, Inflation and Other Uncertainties

56

 

 

Recently Issued Accounting Standards                                                            

58

 

 

Critical Accounting Estimates

58

 

 

Management’s Report on Internal Control Over Financial Reporting

63

 

 

Report of Independent Registered Public Accounting Firm

64

 

 

Consolidated Financial Statements

 

 

 

Statement of Income

66

 

 

Statement of Comprehensive Income

67

 

 

Balance Sheet

68

 

 

Statement of Cash Flows

69

 

 

Statement of Changes in Equity

70

 

 

Notes to Consolidated Financial Statements

 

 

 

  1. Summary of Accounting Policies

71

 

 

  2. Accounting Changes

75

 

 

  3. Miscellaneous Financial Information

76

 

 

  4. Other Comprehensive Income Information

77

 

 

  5. Cash Flow Information

78

 

 

  6. Additional Working Capital Information

78

 

 

  7. Equity Company Information

79

 

 

  8. Investments, Advances and Long-Term Receivables

81

 

 

  9. Property, Plant and Equipment and Asset Retirement Obligations

81

 

 

10. Accounting for Suspended Exploratory Well Costs

83

 

 

11. Leased Facilities

85

 

 

12. Earnings Per Share

86

 

 

13. Financial Instruments and Derivatives

86

 

 

14. Long-Term Debt

88

 

 

15. Incentive Program

89

 

 

16. Litigation and Other Contingencies

90

 

 

17. Pension and Other Postretirement Benefits

92

 

 

18. Disclosures about Segments and Related Information

100

 

 

19. Income and Other Taxes

103

 

 

Supplemental Information on Oil and Gas Exploration and Production Activities

107

 

 

Operating Information

122

 

35 


BUSINESS PROFILE

 

 

 

 

 

 

 

 

 

 

 

 

 

Return on

 

 

Capital and

 

 

 

 

Earnings After

 

Average Capital

 

Average Capital

 

 

Exploration

 

 

 

 

Income Taxes

 

Employed

 

Employed

 

 

Expenditures

Financial

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

 

2018

 

2017

 

 

 

 

(millions of dollars)

 

(percent)

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

1,739

 

6,622

 

69,981

 

64,896

 

2.5

 

10.2

 

 

7,670

 

3,716

 

Non-U.S.

 

12,340

 

6,733

 

107,893

 

109,778

 

11.4

 

6.1

 

 

12,524

 

12,979

 

 

Total

 

14,079

 

13,355

 

177,874

 

174,674

 

7.9

 

7.6

 

 

20,194

 

16,695

Downstream

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

2,962

 

1,948

 

8,725

 

7,936

 

33.9

 

24.5

 

 

1,186

 

823

 

Non-U.S.

 

3,048

 

3,649

 

17,015

 

14,578

 

17.9

 

25.0

 

 

2,243

 

1,701

 

 

Total

 

6,010

 

5,597

 

25,740

 

22,514

 

23.3

 

24.9

 

 

3,429

 

2,524

Chemical

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United States

 

1,642

 

2,190

 

12,171

 

10,672

 

13.5

 

20.5

 

 

1,747

 

1,583

 

Non-U.S.

 

1,709

 

2,328

 

18,249

 

16,844

 

9.4

 

13.8

 

 

488

 

2,188

 

 

Total

 

3,351

 

4,518

 

30,420

 

27,516

 

11.0

 

16.4

 

 

2,235

 

3,771

Corporate and financing

 

(2,600)

 

(3,760)

 

(1,660)

 

(2,073)

 

-

 

-

 

 

65

 

90

 

 

Total

 

20,840

 

19,710

 

232,374

 

222,631

 

9.2

 

9.0

 

 

25,923

 

23,080

 

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




 

Operating

2018

 

2017

 

 

 

 

2018

 

2017

 

 

(thousands of barrels daily)

 

 

 

(thousands of barrels daily)

Net liquids production

 

 

 

 

Refinery throughput

 

 

 

 

United States

551

 

514

 

 

United States

1,588

 

1,508

 

Non-U.S.

1,715

 

1,769

 

 

Non-U.S.

2,684

 

2,783

 

 

Total

2,266

 

2,283

 

 

 

Total

4,272

 

4,291

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of cubic feet daily)

 

 

 

(thousands of barrels daily)

Natural gas production available for sale

 

 

 

 

Petroleum product sales (2) 

 

 

 

 

United States

2,574

 

2,936

 

 

United States

2,210

 

2,190

 

Non-U.S.

6,831

 

7,275

 

 

Non-U.S.

3,302

 

3,340

 

 

Total

9,405

 

10,211

 

 

 

Total

5,512

 

5,530

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

 

 

 

(thousands of metric tons)

Oil-equivalent production (1) 

3,833

 

3,985

 

Chemical prime product sales (2) (3)

 

 

 

 

 

 

 

 

 

 

 

United States

9,824

 

9,307

 

 

 

 

 

 

 

 

Non-U.S.

17,045

 

16,113

 

 

 

 

 

 

 

 

 

Total

26,869

 

25,420

 

(1)     Natural gas is converted to an oil-equivalent basis at six million cubic feet per one 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 including ExxonMobil’s share of equity company volumes and finished-product transfers to the Downstream.

  

 

36 


FINANCIAL INFORMATION

 

 

 

 

2018

 

2017

 

2016

 

2015

 

2014

 

 

(millions of dollars, except where stated otherwise)

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue

 

279,332

 

237,162

 

200,628

 

239,854

 

367,647

Earnings

 

 

 

 

 

 

 

 

 

 

 

Upstream

 

14,079

 

13,355

 

196

 

7,101

 

27,548

 

Downstream

 

6,010

 

5,597

 

4,201

 

6,557

 

3,045

 

Chemical

 

3,351

 

4,518

 

4,615

 

4,418

 

4,315

 

Corporate and financing

 

(2,600)

 

(3,760)

 

(1,172)

 

(1,926)

 

(2,388)

 

Net income attributable to ExxonMobil

 

20,840

 

19,710

 

7,840

 

16,150

 

32,520

Earnings per common share (dollars)

 

4.88

 

4.63

 

1.88

 

3.85

 

7.60

Earnings per common share – assuming dilution (dollars)

 

4.88

 

4.63

 

1.88

 

3.85

 

7.60

 

 

 

 

 

 

 

 

 

 

 

 

Earnings to average ExxonMobil share of equity (percent)

 

11.0

 

11.1

 

4.6

 

9.4

 

18.7

 

 

 

 

 

 

 

 

 

 

 

 

Working capital

 

(9,165)

 

(10,637)

 

(6,222)

 

(11,353)

 

(11,723)

Ratio of current assets to current liabilities (times)

 

0.84

 

0.82

 

0.87

 

0.79

 

0.82

 

 

 

 

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

20,051

 

24,901

 

16,100

 

27,475

 

34,256

Property, plant and equipment, less allowances

 

247,101

 

252,630

 

244,224

 

251,605

 

252,668

Total assets

 

346,196

 

348,691

 

330,314

 

336,758

 

349,493

 

 

 

 

 

 

 

 

 

 

 

 

Exploration expenses, including dry holes

 

1,466

 

1,790

 

1,467

 

1,523

 

1,669

Research and development costs

 

1,116

 

1,063

 

1,058

 

1,008

 

971

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

20,538

 

24,406

 

28,932

 

19,925

 

11,653

Total debt

 

37,796

 

42,336

 

42,762

 

38,687

 

29,121

Debt to capital (percent)

 

16.0

 

17.9

 

19.7

 

18.0

 

13.9

Net debt to capital (percent) (1) 

 

14.9

 

16.8

 

18.4

 

16.5

 

11.9

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil share of equity at year-end

 

191,794

 

187,688

 

167,325

 

170,811

 

174,399

ExxonMobil share of equity per common share (dollars)

 

45.27

 

44.28

 

40.34

 

41.10

 

41.51

Weighted average number of common shares

 

 

 

 

 

 

 

 

 

 

 

outstanding (millions)

 

4,270

 

4,256

 

4,177

 

4,196

 

4,282

 

 

 

 

 

 

 

 

 

 

 

 

Number of regular employees at year-end (thousands) (2) 

 

71.0

 

69.6

 

71.1

 

73.5

 

75.3

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)   Debt net of cash.

(2)   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 is not significant.

  

 

37 


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

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

36,014

 

30,066

 

22,082

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

 

 

 

 

 

 

 

and sales and returns of investments

 

4,123

 

3,103

 

4,275

 

Cash flow from operations and asset sales

 

40,137

 

33,169

 

26,357

 

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

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

Business uses: asset and liability perspective

 

 

 

 

 

 

Total assets

 

346,196

 

348,691

 

330,314

Less liabilities and noncontrolling interests share of assets and liabilities

 

 

 

 

 

 

 

Total current liabilities excluding notes and loans payable

 

(39,880)

 

(39,841)

 

(33,808)

 

Total long-term liabilities excluding long-term debt

 

(69,992)

 

(72,014)

 

(79,914)

 

Noncontrolling interests share of assets and liabilities

 

(7,958)

 

(8,298)

 

(8,031)

Add ExxonMobil share of debt-financed equity company net assets

 

3,914

 

3,929

 

4,233

 

Total capital employed

 

232,280

 

232,467

 

212,794

 

 

 

 

 

 

 

 

Total corporate sources: debt and equity perspective

 

 

 

 

 

 

Notes and loans payable

 

17,258

 

17,930

 

13,830

Long-term debt

 

20,538

 

24,406

 

28,932

ExxonMobil share of equity

 

191,794

 

187,688

 

167,325

Less noncontrolling interests share of total debt

 

(1,224)

 

(1,486)

 

(1,526)

Add ExxonMobil share of equity company debt

 

3,914

 

3,929

 

4,233

 

Total capital employed

 

232,280

 

232,467

 

212,794

38 


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

 

2018

 

2017

 

2016

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income attributable to ExxonMobil

 

20,840

 

19,710

 

7,840

Financing costs (after tax)

 

 

 

 

 

 

 

Gross third-party debt

 

(912)

 

(709)

 

(683)

 

ExxonMobil share of equity companies

 

(192)

 

(204)

 

(225)

 

All other financing costs – net

 

498

 

515

 

423

 

 

Total financing costs

 

(606)

 

(398)

 

(485)

 

 

 

Earnings excluding financing costs

 

21,446

 

20,108

 

8,325

 

 

 

 

 

 

 

 

 

 

Average capital employed

 

232,374

 

222,631

 

212,226

 

 

 

 

 

 

 

 

 

 

Return on average capital employed – corporate total

 

9.2%

 

9.0%

 

3.9%

39 


QUARTERLY INFORMATION

 

 

 

2018

 

2017

 

 

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,

2,216

2,212

2,286

2,348

2,266

 

2,333

2,269

2,280

2,251

2,283

 

synthetic oil and bitumen

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

4,293

4,105

4,392

4,298

4,272

 

4,324

4,345

4,287

4,207

4,291

Petroleum product sales (1) 

5,432

5,502

5,616

5,495

5,512

 

5,395

5,558

5,542

5,624

5,530

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production

(millions of cubic feet daily)

 

available for sale

10,038

8,613

9,001

9,974

9,405

 

10,908

9,920

9,585

10,441

10,211

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (2) 

3,889

3,647

3,786

4,010

3,833

 

4,151

3,922

3,878

3,991

3,985

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of metric tons)

Chemical prime product sales (1) 

6,668

6,852

6,677

6,672

26,869

 

6,072

6,120

6,446

6,782

25,420

 

 

 

 

 

 

 

 

 

 

 

 

 

Summarized financial data

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating

(millions of dollars)

 

revenue

65,436

71,456

74,187

68,253

279,332

 

56,474

56,026

59,350

65,312

237,162

Gross profit (3) 

16,187

16,622

18,656

16,268

67,733

 

14,030

13,120

15,086

14,126

56,362

Net income attributable to

 

 

 

 

 

 

 

 

 

 

 

 

ExxonMobil(4) 

4,650

3,950

6,240

6,000

20,840

 

4,010

3,350

3,970

8,380

19,710

 

 

 

 

 

 

 

 

 

 

 

 

 

Per share data

(dollars per share)

Earnings per common share (5) 

1.09

0.92

1.46

1.41

4.88

 

0.95

0.78

0.93

1.97

4.63

Earnings per common share

 

 

 

 

 

 

 

 

 

 

 

 

– assuming dilution (5) 

1.09

0.92

1.46

1.41

4.88

 

0.95

0.78

0.93

1.97

4.63

 

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

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

(3)   Gross profit equals sales and other operating revenue less estimated costs associated with products sold. Effective January 1, 2018, the Corporation adopted the Accounting Standard Update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost which requires separate presentation of the non-service cost components of net benefit costs and increased previously reported gross profit by $279 million for first quarter 2017, $347 million for second quarter 2017, $382 million for third quarter 2017, and $430 million for fourth quarter 2017. See Note 2 to the financial statements, Accounting Changes.

(4)   Fourth quarter 2018 included an impairment charge of $429 million. Fourth quarter 2017 included a U.S. tax reform impact of $5,942 million and an impairment charge of $1,294 million.

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

 

The 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 371,146 registered shareholders of ExxonMobil common stock at December 31, 2018. At January 31, 2019, the registered shareholders of ExxonMobil common stock numbered 370,064.

On January 30, 2019, the Corporation declared a $0.82 dividend per common share, payable March 11, 2019.

 

40 


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

 

FUNCTIONAL EARNINGS

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars, except per share amounts)

Earnings (U.S. GAAP)

 

 

 

 

 

 

Upstream

 

 

 

 

 

 

 

United States

 

1,739

 

6,622

 

(4,151)

 

Non-U.S.

 

12,340

 

6,733

 

4,347

Downstream

 

 

 

 

 

 

 

United States

 

2,962

 

1,948

 

1,094

 

Non-U.S.

 

3,048

 

3,649

 

3,107

Chemical

 

 

 

 

 

 

 

United States

 

1,642

 

2,190

 

1,876

 

Non-U.S.

 

1,709

 

2,328

 

2,739

Corporate and financing

 

(2,600)

 

(3,760)

 

(1,172)

 

 

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

 

20,840

 

19,710

 

7,840

 

 

 

 

 

 

 

 

 

Earnings per common share

 

4.88

 

4.63

 

1.88

Earnings per common share – assuming dilution

 

4.88

 

4.63

 

1.88

 

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 or conditions, including demand growth and energy source, supply and mix; government policies relating to climate change, foreign relations and taxation; project plans, capacities, schedules and costs; production growth and mix; rates of field decline; asset carrying values; proved reserves; financing sources; the resolution of contingencies and uncertain tax positions; and 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; the outcome of exploration and development projects; technological developments; 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 integrated business model involving exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.

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 depend on supply and demand and may be volatile on a short-term basis, ExxonMobil’s investment decisions are grounded on fundamentals reflected in our long-term business outlook, and use 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. Major investment opportunities are evaluated over a range of potential market conditions. Once major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

41 


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

 

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

The Long-Term Business Outlook is based on the Corporation’s 2018 Outlook for Energy, which is used to help inform our long term business strategies and investment plans. By 2040, the world’s population is projected at around 9.2 billion people, or about 1.7 billion more than in 2016. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year, with economic output nearly doubling by 2040. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 25 percent from 2016 to 2040. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organisation for Economic Co-operation and Development (OECD)).

As expanding prosperity helps drive global energy demand higher, increasing use of energy efficient technologies and practices as well as lower-emission fuels 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 power generation, transportation, industrial applications, and residential and commercial needs.

Global electricity demand is expected to increase approximately 60 percent from 2016 to 2040, with developing countries likely to account for about 85 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal fired generation is likely to decline substantially and approach 25 percent of the world’s electricity in 2040, versus nearly 40 percent in 2016, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks of climate change. From 2016 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to nearly double, and account for about 95 percent of the growth in electricity supplies. Electricity from wind and solar is likely to increase about 400 percent, helping total renewables (including other sources, e.g. hydropower) to account for about half of the increase in electricity supplies worldwide through 2040. Total renewables will likely reach nearly 35 percent of global electricity supplies by 2040. Natural gas and nuclear are also expected to increase shares over the period to 2040, reaching about 25 percent and 12 percent of global electricity supplies respectively by 2040. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase approximately 30 percent from 2016 to 2040. Transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period. Liquid fuels demand for light-duty vehicles is expected to remain relatively flat to 2040 as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 75 percent. By 2040, light-duty vehicles are expected to account for about 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s transportation fleets are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.

Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2040, global demand for liquid fuels is projected to grow to approximately 118 million barrels of oil equivalent per day, an increase of about 20 percent from 2016. The non-OECD share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely to decline by close to 10 percent. Much of the global liquid fuels demand today is met by crude production from traditional conventional sources; these supplies will remain important and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels – are expected to grow to help meet rising demand. 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, timely investments will remain critical to meeting global needs with reliable and affordable supplies.

Natural gas is a versatile and practical fuel for a wide variety of applications, and it is expected to grow the most of any primary energy type from 2016 to 2040, meeting more than 35 percent of global energy demand growth. Global natural gas demand is expected to rise nearly 40 percent from 2016 to 2040, with about 45 percent of that increase in the Asia Pacific region. Significant growth in supplies of unconventional gas – the natural gas found in shale and other tight rock formations – will help meet these needs. In total, about 55 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting about two-thirds of worldwide demand in 2040. Liquefied natural gas (LNG) trade will expand significantly, meeting about one-third of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.

42 


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

 

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 2020-2025 timeframe. The share of natural gas is expected to reach 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 exceed 15 percent of global 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 nearly 250 percent from 2016 to 2040, when they will likely be about 5 percent of the world energy mix.

The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2040 will be significant – even if demand remains flat. This reflects a fundamental aspect of the oil and natural gas business, in that, as the International Energy Agency (IEA) notes in its World Energy Outlook 2018, a “key underlying driver for new investment is declining output from existing fields.” According to the IEA’s New Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over the period 2018-2040 will be about $21 trillion (measured in 2017 dollars) or approximately $900 billion 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. The climate accord reached at the Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. Our Outlook  reflects an environment with increasingly stringent climate policies and is consistent with the aggregation of Nationally Determined Contributions which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement. Our Outlook  seeks to identify potential impacts of climate related policies, which often target specific sectors. It estimates potential impacts of these policies on consumer energy demand by using various assumptions and tools – including, depending on the sector, application of a proxy cost of carbon or assessment of targeted policies (e.g. automotive fuel economy standards). For purposes of the Outlook, a proxy cost on energy-related CO2 emissions is assumed to reach about $80 per tonne on average in 2040 in OECD nations. 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.

Practical solutions to the world’s energy and climate challenges will benefit from market competition as well as well informed, well designed, and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and water, access to reliable, affordable energy, and economic progress for all people. All practical and economically-viable energy sources, both conventional and unconventional, will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs as well as the importance of expanding access to modern energy to promote better standards of living for billions of people.

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 sustain a diverse growth 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 strategies guide our global Upstream business, including capturing material and accretive opportunities to continually high-grade the resource portfolio, selectively developing attractive oil and natural gas resources, developing and applying high-impact technologies, and pursuing productivity and efficiency gains. These strategies are underpinned by a relentless focus on operational excellence, 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. Based on current investment plans, oil-equivalent production from the Americas is expected to increase to be a majority of total production over the next several years. Further, the proportion of our global production from unconventional, deepwater, and LNG resource types, currently contributes over a third of global production, and is expected to grow to be more than half in the next few years.

 

 

43 


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

 

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 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 general economic activities, levels of prosperity, technology advances, consumer preference and government policies. 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 major investments across a range of price scenarios.

In 2018, the Upstream business produced 3.8 million oil-equivalent barrels per day. During the year, the Corporation added 4.5 billion oil-equivalent barrels of proved reserves. The Corporation continued to have exploration success in Guyana and also made strategic acreage acquisitions in Mozambique, Brazil, Papua New Guinea and U.S. tight oil.

 

Downstream

ExxonMobil’s Downstream is a large, diversified business with global logistics, trading, refining, and marketing. The Corporation has a presence with established markets in the Americas and Europe, as well as in the growing Asia Pacific region.

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 21 refineries, located in 14 countries, with distillation capacity of 4.7 million barrels per day and lubricant basestock manufacturing capacity of 128 thousand barrels per day. ExxonMobil’s fuels and lubes value chains have significant global reach, with multiple channels to market serving a diverse customer base. Our portfolio of world-renowned brands includes Exxon, Mobil, Esso, Synergy, and Mobil 1.  

Demand for products continued to grow in 2018. North America’s margins strengthened and refineries within the region also benefitted from crude differentials associated with the Permian Basin and Western Canada. Margins in Europe and Asia weakened under pressure from lower cost production from North America and increased product exports from China. In the near term, we see variability in refining margins as new capacity additions are expected to outpace capacity rationalization and growth in global demand, 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 volatile subject to the pace of new capacity growth relative to global demand growth. ExxonMobil’s integration including logistics, trading, refining, and marketing enhances our ability to generate returns across the value chain 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.

44 


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

 

ExxonMobil continued to progress 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 lubricants business continues to grow, leveraging world class brands and integration with industry leading basestock refining capability. Through the Mobil Branded properties, such as Mobil 1, Mobil is the worldwide leader among synthetic motors oils.

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. At the end of 2018, three key projects are in operation with the new delayed coker unit at the refinery in Antwerp, Belgium, to upgrade low value bunker fuel into higher value diesel products, and the proprietary hydrocracker at the refinery in Rotterdam, Netherlands, to produce higher value ultra-low sulfur diesel and Group II basestocks. Finally, the new hydrofiner at the Beaumont, Texas, refinery was completed, which increases production of ultra-low sulfur fuels by approximately 40,000 barrels per day.

 

Chemical

ExxonMobil is a major manufacturer and marketer of petrochemicals and a wide variety of specialty products. ExxonMobil sustains its competitive advantage through continued operational excellence, investment and cost discipline, a balanced portfolio of products, and integration with downstream and upstream operations, all underpinned by proprietary technology.

Demand for products continued to grow in 2018. Polyolefin and specialty product margins weakened with capacity additions outpacing global demand growth.

Over the long term, demand for chemical products is forecast to outpace growth in global GDP and energy demand for the next two decades. ExxonMobil estimates that global demand for chemicals will rise by approximately 45 percent over the next decade. ExxonMobil’s integration with refining enhances our ability to generate returns across the value chain in chemical businesses.

In 2018, we completed start-up of the new world-scale ethane cracker in Baytown, Texas, the specialty elastomer plant expansion in Newport, Wales, and the new halobutyl rubber unit in Singapore to further extend our specialty product capacity. Construction continues on the expansion of the polyethylene plant in Beaumont, Texas, with startup anticipated in 2019, to capitalize on advantaged feedstock and energy supplies in North America and to meet rapidly growing demand for performance polymers. Work continues to integrate the Singapore Banyan Aromatics unit, acquired in 2017, with our other Singapore facilities to meet growing demand for chemicals products in Asia Pacific. In addition, ExxonMobil announced plans for a flexible-feed cracker in Guangdong Province, China, and a joint venture ethane cracker and associated products with SABIC to be located in San Patricio County, Texas.

45 


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

 

REVIEW OF 2018 AND 2017 RESULTS

 

 

 

 

 

2018

 

2017

 

2016

 

 

(millions of dollars)

Earnings (U.S. GAAP)

 

 

 

 

 

 

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

 

20,840

 

19,710

 

7,840



 

Upstream

 

 

 

 

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

Upstream

 

 

 

 

 

 

 

United States

 

1,739

 

6,622

 

(4,151)

 

Non-U.S.

 

12,340

 

6,733

 

4,347

 

 

Total

 

14,079

 

13,355

 

196

 

2018

Upstream earnings were $14,079 million, up $724 million from 2017.

·          Higher realizations increased earnings by $7 billion.

·          Unfavorable volume and mix effects decreased earnings by $240 million.

·          All other items decreased earnings by $6.1 billion, primarily due to lower favorable impacts of $6.9 billion from U.S. tax reform, partly offset by lower asset impairments of $1.1 billion.

·          U.S. Upstream earnings were $1,739 million, including asset impairments of $297 million.

·          Non‑U.S. Upstream earnings were $12,340 million, including a favorable impact of $271 million from U.S. tax reform.

·          On an oil‑equivalent basis, production of 3.8 million barrels per day was down 4 percent compared to 2017.

·          Liquids production of 2.3 million barrels per day decreased 17,000 barrels per day as growth in North America was more than offset by decline, lower entitlements, and divestments.

·          Natural gas production of 9.4 billion cubic feet per day decreased 806 million cubic feet per day from 2017 due to decline, lower entitlements, divestments, and higher downtime.

 

2017

Upstream earnings were $13,355 million, up $13,159 million from 2016.

·          Higher realizations increased earnings by $5.3 billion.

·          Unfavorable volume and mix effects decreased earnings by $440 million.

·          All other items increased earnings by $8.3 billion, primarily due to the $7.1 billion non‑cash impact from U.S. tax reform, lower asset impairments of $659 million, lower expenses, and gains from asset management activity.

·          U.S. Upstream earnings were $6,622 million in 2017, including $7.6 billion of U.S. tax reform benefits and asset impairments of $521 million.

·          Non‑U.S. Upstream earnings were $6,733 million, including asset impairments of $983 million and unfavorable impacts of $480 million from U.S. tax reform.

·          On an oil‑equivalent basis, production of 4 million barrels per day was down 2 percent compared to 2016.

·          Liquids production of 2.3 million barrels per day decreased 82,000 barrels per day as field decline and lower entitlements were partly offset by increased project volumes and work programs.

·          Natural gas production of 10.2 billion cubic feet per day increased 84 million cubic feet per day from 2016 as project ramp‑up, primarily in Australia, was partly offset by field decline and regulatory restrictions in the Netherlands.

46 


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

 

Upstream Additional Information

 

 

 

 

 

 

 

 

 

 

 

2018

 

2017

 

 

 

 

(thousands of barrels daily)

Volumes Reconciliation (Oil-equivalent production) (1) 

 

 

 

 

 

Prior Year

 

 

 

3,985

 

4,053

 

Entitlements - Net Interest

 

 

 

(3)

 

-

 

Entitlements - Price / Spend / Other

 

 

 

(68)

 

(62)

 

Quotas

 

 

 

-

 

-

 

Divestments

 

 

 

(58)

 

(15)

 

Growth / Other

 

 

 

(23)

 

9

Current Year

 

 

 

3,833

 

3,985

 

 

 

 

 

 

 

 

(1) Natural gas is converted to an oil-equivalent basis at six million cubic feet per one 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.

47 


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

 

Downstream

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

Downstream

 

 

 

 

 

 

 

United States

 

2,962

 

1,948

 

1,094

 

Non-U.S.

 

3,048

 

3,649

 

3,107

 

 

Total

 

6,010

 

5,597

 

4,201

 

2018

Downstream earnings of $6,010 million increased $413 million from 2017.

·          Margins increased earnings by $660 million primarily due to the capture of North American crude differentials.

·          Volume and mix effects increased earnings by $650 million due to improved yield/sales mix.

·          All other items decreased earnings by $900 million, mainly driven by the absence of favorable U.S. tax reform impacts of $618 million, unfavorable foreign exchange impacts, and higher downtime/maintenance, partly offset by higher divestment gains and favorable tax impacts.

·          U.S. Downstream earnings were $2,962 million, compared to $1,948 million in the prior year which included a favorable impact of $618 million from U.S. tax reform.

·          Non‑U.S. Downstream earnings were $3,048 million, compared to $3,649 million in the prior year.

·          Petroleum product sales of 5.5 million barrels per day were 18,000 barrels per day lower than 2017.

 

2017

Downstream earnings of $5,597 million increased $1,396 million from 2016.

·          Stronger refining and marketing margins increased earnings by $1.5 billion.

·          Volume and mix effects decreased earnings by $30 million.

·          All other items decreased earnings by $40 million, driven by the absence of a $904 million gain from the Canadian retail assets sale, and Hurricane Harvey related expenses, which were mostly offset by $618 million of U.S. tax reform impacts and non‑U.S. asset management gains in 2017.

·          U.S. Downstream earnings were $1,948 million, including favorable U.S. tax reform impacts of $618 million.

·          Non‑U.S. Downstream earnings were $3,649 million, compared to $3,107 million in the prior year.

·          Petroleum product sales of 5.5 million barrels per day were 48,000 barrels per day higher than 2016.

  

48 


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

 

Chemical

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

Chemical

 

 

 

 

 

 

 

United States

 

1,642

 

2,190

 

1,876

 

Non-U.S.

 

1,709

 

2,328

 

2,739

 

 

Total

 

3,351

 

4,518

 

4,615

 

2018

Chemical earnings of $3,351 million decreased $1,167 million from 2017.

·          Weaker margins decreased earnings by $910 million.

·          Volume and mix effects increased earnings by $280 million, primarily due to sales growth.

·          All other items decreased earnings by $540 million, primarily due to the absence of favorable impacts from U.S. tax reform of $335 million, higher downtime/maintenance, and growth-related expenses, partly offset by a favorable tax item and favorable foreign exchange impacts.

·          U.S. Chemical earnings were $1,642 million in 2018, compared with $2,190 million in the prior year which included $335 million in favorable impacts from U.S. tax reform.

·          Non‑U.S. Chemical earnings were $1,709 million, compared with $2,328 million in the prior year.

·          Prime product sales of 26.9 million metric tons were up 1.4 million metric tons from 2017.

 

2017

Chemical earnings of $4,518 million decreased $97 million from 2016.

·          Weaker margins decreased earnings by $260 million.

·          Volume and mix effects increased earnings by $100 million.

·          All other items increased earnings by $60 million, primarily due to U.S. tax reform of $335 million and improved inventory effects, partially offset by higher expenses from increased turnaround activity and new business growth.

·          U.S. Chemical earnings were $2,190 million in 2017, including favorable U.S. tax reform impacts of $335 million.

·          Non‑U.S. Chemical earnings of $2,328 million were $411 million lower than prior year.

·          Prime product sales of 25.4 million metric tons were up 495,000 metric tons from 2016.

  



Corporate and Financing

 

 

 

 

2018

 

2017

 

2016

 

 

(millions of dollars)

 

 

 

 

 

 

 

Corporate and financing

 

(2,600)

 

(3,760)

 

(1,172)

 

2018

Corporate and financing expenses were $2,600 million in 2018 compared to $3,760 million in 2017, with the decrease mainly due to absence of prior year unfavorable impacts of $2.1 billion from U.S. tax reform, partly offset by higher pension and financing related costs, lower U.S. tax rate, and lower net favorable tax items.

 

2017

Corporate and financing expenses were $3,760 million in 2017 compared to $1,172 million in 2016, with the increase mainly due to unfavorable impacts of $2.1 billion from U.S. tax reform and the absence of favorable non-U.S. tax items.

49 


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

 

LIQUIDITY AND CAPITAL RESOURCES

 

 

 

 

 

 

 

 

 

 

 

Sources and Uses of Cash

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

Net cash provided by/(used in)

 

 

 

 

 

 

 

Operating activities

 

36,014

 

30,066

 

22,082

 

Investing activities

 

(16,446)

 

(15,730)

 

(12,403)

 

Financing activities

 

(19,446)

 

(15,130)

 

(9,293)

Effect of exchange rate changes

 

(257)

 

314

 

(434)

Increase/(decrease) in cash and cash equivalents

 

(135)

 

(480)

 

(48)

 

 

 

 

 

 

 

 

 

 

 

(December 31)

Total cash and cash equivalents

 

3,042

 

3,177

 

3,657

 

 

 

 

 

 

 

 

Total cash and cash equivalents were $3.0 billion at the end of 2018, down $0.1 billion from the prior year. The major sources of funds in 2018 were net income including noncontrolling interests of $21.4 billion, the adjustment for the noncash provision of $18.7 billion for depreciation and depletion, and proceeds from asset sales of $4.1 billion. The major uses of funds included spending for additions to property, plant and equipment of $19.6 billion, dividends to shareholders of $13.8 billion, net debt repayments of $4.9 billion, an increase in inventories of $3.1 billion, the adjustment for net gains on asset sales of $2.0 billion, and additional investments and advances of $2.0 billion.

Total cash and cash equivalents were $3.2 billion at the end of 2017, down $0.5 billion from the prior year. The major sources of funds in 2017 were net income including noncontrolling interests of $19.8 billion, the adjustment for the noncash provision of $19.9 billion for depreciation and depletion, proceeds from asset sales of $3.1 billion, and other investing activities including collection of advances of $2.1 billion. The major uses of funds included spending for additions to property, plant and equipment of $15.4 billion, dividends to shareholders of $13.0 billion, the adjustment for noncash deferred income tax credits of $8.6 billion, and additional investments and advances of $5.5 billion.

The Corporation has access to significant capacity of long-term and short-term liquidity. Internally generated funds are generally expected to cover financial requirements, supplemented by short-term and long-term debt as required. On December 31, 2018, the Corporation had unused committed short-term lines of credit of $5.3 billion and unused committed long-term lines of credit of $0.2 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 or acquire 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 and growth in key tight-oil plays, 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. 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.

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2018 were $25.9 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment level of approximately $30 billion in 2019.

 

 

50 


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

 

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.

 

ExxonMobil closely monitors the potential impacts of Brexit and LIBOR reform under a number of scenarios and has taken steps to mitigate their potential impact. Accordingly, ExxonMobil does not believe these events represent a material risk to the Corporation’s consolidated results of operations or financial condition.

 

Cash Flow from Operating Activities

 

2018

Cash provided by operating activities totaled $36.0 billion in 2018, $5.9 billion higher than 2017. The major source of funds was net income including noncontrolling interests of $21.4 billion, an increase of $1.6 billion. The noncash provision for depreciation and depletion was $18.7 billion, down $1.1 billion from the prior year. The adjustment for the net gain on asset sales was $2.0 billion, an increase of $1.7 billion. The adjustment for dividends received less than equity in current earnings of equity companies was a reduction of $1.7 billion, compared to an increase of $0.1 billion in 2017. The adjustment for deferred income tax credits was $0.1 billion, compared to $8.6 billion in 2017. Changes in operational working capital, excluding cash and debt, decreased cash in 2018 by $1.4 billion.

 

2017

Cash provided by operating activities totaled $30.1 billion in 2017, $8.0 billion higher than 2016. The major source of funds was net income including noncontrolling interests of $19.8 billion, an increase of $11.5 billion. The noncash provision for depreciation and depletion was $19.9 billion, down $2.4 billion from the prior year. The adjustment for deferred income tax credits was $8.6 billion, compared to $4.4 billion in 2016. Changes in operational working capital, excluding cash and debt, decreased cash in 2017 by $0.6 billion.

  

Cash Flow from Investing Activities

 

2018

Cash used in investing activities netted to $16.4 billion in 2018, $0.7 billion higher than 2017. Spending for property, plant and equipment of $19.6 billion increased $4.2 billion from 2017. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $4.1 billion compared to $3.1 billion in 2017. Additional investments and advances were $3.5 billion lower in 2018, while proceeds from other investing activities including collection of advances decreased by $1.1 billion.

 

2017

Cash used in investing activities netted to $15.7 billion in 2017, $3.3 billion higher than 2016. Spending for property, plant and equipment of $15.4 billion decreased $0.8 billion from 2016. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $3.1 billion compared to $4.3 billion in 2016. Additional investments and advances were $4.1 billion higher in 2017, while proceeds from other investing activities including collection of advances increased by $1.2 billion.

  

51 


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

 

Cash Flow from Financing Activities

 

2018

Cash used in financing activities was $19.4 billion in 2018, $4.3 billion higher than 2017. Dividend payments on common shares increased to $3.23 per share from $3.06 per share and totaled $13.8 billion. Total debt decreased $4.5 billion to $37.8 billion at year‑end. The reduction was principally driven by net short-term debt and commercial paper repayments of $5.0 billion.

ExxonMobil share of equity increased $4.1 billion to $191.8 billion. The addition to equity for earnings was $20.8 billion. This was partly offset by reductions for distributions to ExxonMobil shareholders of $13.8 billion, all in the form of dividends. Foreign exchange translation effects of $4.4 billion for the stronger U.S. currency reduced equity, while a $1.1 billion change in the funded status of the postretirement benefits reserves increased equity.

During 2018, Exxon Mobil Corporation acquired 8 million shares of its common stock for the treasury. Purchases were made to offset shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding decreased from 4,239 million to 4,237 million at the end of 2018.

 

2017

Cash used in financing activities was $15.1 billion in 2017, $5.8 billion higher than 2016. Dividend payments on common shares increased to $3.06 per share from $2.98 per share and totaled $13.0 billion. Total debt decreased $0.4 billion to $42.3 billion at year‑end. The reduction was principally driven by net repayments of $1.0 billion, and included short-term debt repayments of $5.0 billion that were partly offset by additions in commercial paper and other debt of $4.0 billion.

ExxonMobil share of equity increased $20.4 billion to $187.7 billion. The addition to equity for earnings was $19.7 billion. This was partly offset by reductions for distributions to ExxonMobil shareholders of $13.0 billion, all in the form of dividends. Foreign exchange translation effects of $5.0 billion for the weaker U.S. currency and a $1.0 billion change in the funded status of the postretirement benefits reserves both increased equity. Shares issued for acquisitions added $7.8 billion to equity.

During 2017, Exxon Mobil Corporation acquired 10 million shares of its common stock for the treasury. Purchases were made to offset shares or units settled in shares issued in conjunction with the company’s benefit plans and programs. Shares outstanding increased from 4,148 million to 4,239 million at the end of 2017, mainly due to a total of 96 million shares issued for the acquisitions of InterOil Corporation and of companies that hold acreage in the Permian Basin.

  

52 


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, 2018. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

 

 

 

Payments Due by Period

 

 

Note

 

 

 

 

 

 

 

2024

 

 

 

 

Reference

 

 

 

2020-

 

2022-

 

and

 

 

Commitments

Number

 

2019

 

2021

 

2023

 

Beyond

 

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt  (1) 

14

 

-

 

4,210

 

3,145

 

13,183

 

20,538

 

 – Due in one year  (2) 

6

 

4,070

 

-

 

-

 

-

 

4,070

Asset retirement obligations  (3) 

9

 

918

 

1,484

 

860

 

8,841

 

12,103

Pension and other postretirement obligations  (4) 

17

 

2,666

 

1,899

 

1,858

 

13,594

 

20,017

Operating leases  (5) 

11

 

1,156

 

1,750

 

1,003

 

2,203

 

6,112

Take-or-pay and unconditional purchase obligations  (6) 

 

 

3,628

 

6,618

 

5,566

 

14,903

 

30,715

Firm capital commitments  (7) 

 

 

7,044

 

2,246

 

1,137

 

1,187

 

11,614

 

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 $9.2 billion as of December 31, 2018, 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 and Other Taxes”.

Notes:

(1)   Includes capitalized lease obligations of $1,303 million.

(2)   The amount due in one year is included in Notes and loans payable of $17,258 million.

(3)   Asset retirement obligations are 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 2019 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 and other assets. Total includes $623 million related to drilling rigs and related equipment.

(6)   Take-or-pay obligations are noncancelable, long-term commitments for goods and services. Unconditional purchase obligations 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 $30,715 million mainly pertain to pipeline, manufacturing supply and terminal agreements.

(7)   Firm capital commitments represent legally binding payment obligations to third parties where agreements specifying all significant terms have been executed for the construction and purchase of fixed assets and other permanent investments. In certain cases where the Corporation executes contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated. Firm capital commitments, shown on an undiscounted basis, totaled $11.6 billion, including $2.5 billion in the U.S.

Firm capital commitments for the non-U.S. Upstream of $8.6 billion were primarily associated with projects in Guyana, Africa, United Kingdom, United Arab Emirates, Malaysia, Australia, Canada and Norway. The Corporation expects to fund the majority of these commitments with internally generated funds, supplemented by short-term and long-term debt as required.

53 


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, 2018, 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, 2018, the Corporation’s unused short-term committed lines of credit totaled $5.3 billion (Note 6) and unused long-term committed lines of credit totaled $0.2 billion (Note 14). The table below shows the Corporation’s consolidated debt-to-capital ratios. The data demonstrates the Corporation’s creditworthiness.

 

 

 

2018

 

2017

 

2016

Debt to capital (percent)

 

16.0

 

17.9

 

19.7

Net debt to capital (percent)

 

14.9

 

16.8

 

18.4

 

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.

 

CAPITAL AND EXPLORATION EXPENDITURES

 

 

 

 

 

 

 

 

 

 

 

 

2018

 

2017

 

 

U.S.

Non-U.S.

Total

 

U.S.

Non-U.S.

Total

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

Upstream (1) 

7,670

 

12,524

 

20,194

 

3,716

 

12,979

 

16,695

Downstream

1,186

 

2,243

 

3,429

 

823

 

1,701

 

2,524

Chemical

1,747

 

488

 

2,235

 

1,583

 

2,188

 

3,771

Other

65

 

-

 

65

 

90

 

-

 

90

 

Total

10,668

 

15,255

 

25,923

 

6,212

 

16,868

 

23,080

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Exploration expenses included.

 

 

 

 

 

 

 

 

 

Capital and exploration expenditures in 2018 were $25.9 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 approximately $30 billion in 2019. Actual spending could vary depending on the progress of individual projects and property acquisitions.

Upstream spending of $20.2 billion in 2018 was up 21 percent from 2017. Investments in 2018 included growth in the U.S. Permian Basin, acreage acquisitions in Brazil and global development projects. Development projects typically take several years from the time of recording proved undeveloped reserves to the start of production and can exceed five years for large and complex projects. The percentage of proved developed reserves was 68 percent of total proved reserves at year‑end 2018, and has been over 60 percent for the last ten years.

Capital investments in the Downstream totaled $3.4 billion in 2018, an increase of $0.9 billion from 2017, reflecting global project spending and a lubricants acquisition in Indonesia. Chemical capital expenditures of $2.2 billion, decreased $1.5 billion, representing investments in growth projects offset by the 2017 acquisition of a large-scale aromatics plant in Singapore.

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

 

TAXES

 

 

 

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Income taxes

 

9,532

 

(1,174)

 

(406)

 

Effective income tax rate

 

37%

 

5%

 

13%

Total other taxes and duties

 

35,230

 

32,459

 

31,375

 

Total

 

44,762

 

31,285

 

30,969

 

 

 

 

 

 

 

 

2018

Total taxes on the Corporation’s income statement were $44.8 billion in 2018, an increase of $13.5 billion from 2017. Income tax expense, both current and deferred, was $9.5 billion compared to a credit of $1.2 billion in 2017. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 37 percent compared to 5 percent. The increase principally reflects the absence of the impact of U.S. tax reform in the prior year. Total other taxes and duties of $35.2 billion in 2018 increased $2.8 billion.

 

2017

Total taxes on the Corporation’s income statement were $31.3 billion in 2017, an increase of $0.3 billion from 2016. Income tax expense, both current and deferred, was a credit of $1.2 billion compared to a credit of $0.4 billion in 2016, with the U.S. tax reform impact of $5.9 billion partially offset by higher pre-tax income. The effective tax rate, which is calculated based on consolidated company income taxes and ExxonMobil’s share of equity company income taxes, was 5 percent compared to 13 percent in the prior year due primarily to the impact of U.S. tax reform. Total other taxes and duties of $32.5 billion in 2017 increased $1.1 billion.

 

U.S. Tax Reform

Following the December 22, 2017, enactment of the U.S. Tax Cuts and Jobs Act, in accordance with Accounting Standard Codification Topic 740 (Income Taxes) and following the guidance outlined in the SEC Staff Accounting Bulletin No. 118, the Corporation included a $5,942 million credit in its 2017 results, representing a reasonable estimate of the income tax effects of the changes in tax law and tax rate. The Corporation’s results for 2018 include a $291 million tax credit, mainly in the Non-U.S. Upstream, reflecting an updated estimate of the impact of U.S. tax reform including clarifications provided in proposed transition tax regulations issued by the U.S. Treasury in 2018. The Corporation has completed its accounting for the enactment-date income tax effects of the U.S. Tax Cuts and Jobs Act in accordance with Accounting Standard Codification Topic 740 (Income Taxes).

55 


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

 

ENVIRONMENTAL MATTERS

  

Environmental Expenditures

 

 

 

 

 

 

 

2018

 

2017

 

 

 

(millions of dollars)

 

 

 

 

 

 

Capital expenditures

 

1,294

 

1,321

Other expenditures

 

3,558

 

3,349

 

Total

 

4,852

 

4,670

 

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 2018 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.9 billion, of which $3.6 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to increase to approximately $5.7 billion in 2019 and 2020. 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 2018 for environmental liabilities were $330 million ($302 million in 2017) and the balance sheet reflects liabilities of $875 million as of December 31, 2018, and $872 million as of December 31, 2017.

 

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations (1) 

 

2018

 

2017

 

2016

 

 

 

Crude oil and NGL ($ per barrel)

 

62.79

 

48.91

 

38.15

Natural gas ($ per thousand cubic feet)

 

3.87

 

3.04

 

2.25

 

 

 

 

 

 

 

(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 $450 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. Similarly, a $0.10 per thousand cubic feet change in the worldwide average gas realization would have approximately a $165 million annual after-tax effect on Upstream consolidated plus equity company earnings, excluding the impact of derivatives. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, results of trading activities, 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.

 

56 


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 its major investments over a range of prices.

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 resulting in an efficient capital base.

 

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 commodity prices, currency rates and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into forward currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2018 and 2017, or results of operations for the years ended 2018, 2017 and 2016. 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. No material market or credit risks to the Corporation’s financial position, results of operations or liquidity exist as a result of the derivatives described in Note 13. 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. Fluctuations in exchange rates are often offsetting and the impacts on ExxonMobil’s geographically and functionally diverse operations are varied. 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. Prices for services and materials continue to evolve in response to constant changes in commodity markets and industry activities, impacting operating and capital costs. The Corporation monitors market trends and works to minimize costs in all commodity price environments through its economies of scale in global procurement and its efficient project management practices.

57 


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

 

RECENTLY ISSUED ACCOUNTING STANDARDS

 

Effective January 1, 2019, the Corporation adopted the Financial Accounting Standards Board’s Standard, Leases (Topic 842), as amended. The standard requires all leases to be recorded on the balance sheet as a right of use asset and a lease liability. The Corporation used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The Corporation applied a policy election to exclude short-term leases from balance sheet recognition and also elected certain practical expedients at adoption. As permitted under these expedients the Corporation did not reassess whether existing contracts are or contain leases, the lease classification for any existing leases, initial direct costs for any existing lease and whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. At January 1, 2019, the operating lease liability is estimated to be in the range of $3.3 billion and the operating lease right of use asset is estimated to be in the range of $4.3 billion, including about $1.0 billion related to prepaid leases. The cumulative effect adjustment is expected to be de minimis.

  

 

CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty 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 Natural Gas Reserves

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines, among other factors. 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 Global Reserves 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.

Oil and natural gas reserves include both proved and unproved reserves.

·          Proved oil and natural gas reserves are determined in accordance with Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-of-month oil and natural gas prices during the reporting year.

Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.

The percentage of proved developed reserves was 68 percent of total proved reserves at year-end 2018 (including both consolidated and equity company reserves), an increase from 66 percent in 2017, and has been over 60 percent for the last ten years. 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, government policy, consumer preferences and significant changes in long-term oil and natural gas prices.

·          Unproved reserves are quantities of oil and natural gas 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.

Revisions in previously estimated volumes of proved reserves for existing fields can occur 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 the average of first-of-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment and facility capacity.

58 


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

 

Unit-of-Production Depreciation

Oil and natural gas reserve quantities are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability.

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 method is used. The straight-line method may be used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.

To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. The effect of this approach on the Corporation’s 2018 depreciation expense versus 2017 was immaterial.

Impairment

The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

·          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.

Asset valuation analyses performed as part of its asset management program and other profitability reviews assist the Corporation in assessing whether events or changes in circumstances indicate 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 an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and production costs. During the lifespan of these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses.

In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.

When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the Corporation’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil price, natural gas price or margin ranges, the Corporation may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment for certain assets.

 

 

59 


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

 

In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production Activities is required to use prices based on the average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the Corporation’s long-term price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.

If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, 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. Cash flows used in recoverability assessments are based on the Corporation’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices, refining and chemical margins, volumes, costs, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the asset group, or discounted cash flows using a discount rate commensurate with the risk. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and relies in part on the Corporation’s planning and budgeting cycle. In 2018, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets, mainly in North America, may not be recoverable. Accordingly, impairment assessments were performed which indicated that certain asset groups assessed have future undiscounted cash flow estimates that do not recover their carrying values. The Corporation’s 2018 results include after-tax charges of $0.5 billion to reduce the carrying value of those assets to fair value.

The assessment of fair values required the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair values included estimates of both proved and unproved reserves, future commodity prices which were consistent with the average of third-party industry experts and government agencies, drilling and development costs, discount rates ranging from 6 percent to 8 percent depending on the characteristics of the asset group, and comparable market transactions. Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s long-term price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases. However, 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 the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.

 

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.

 

60 


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

 

Consolidations

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 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.

 

Pension Benefits

The Corporation and its affiliates sponsor nearly 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 applicable tax rules 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 2018 was 6 percent. The 10‑year and 20‑year actual returns on U.S. pension plan assets were 8 percent and 7 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.

 

 

61 


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

 

 

Litigation Contingencies

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

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

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

 

Tax Contingencies

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

The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained 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 U.S. 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.

  

 

62 


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, 2018.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2018, as stated in their report included in the Financial Section of this report.

 

 

 

 

 

 

Darren W. Woods

Chief Executive Officer

Andrew P. Swiger

Senior Vice President

(Principal Financial Officer)

David S. Rosenthal

Vice President and Controller

(Principal Accounting Officer)

63 


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Shareholders of Exxon Mobil Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Exxon Mobil Corporation and its subsidiaries (the “Corporation”) as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Corporation's internal control over financial reporting as of December 31, 2018 based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Corporation as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.      

Basis for Opinions

The Corporation's management is responsible for these consolidated 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 the Corporation’s consolidated financial statements and on the Corporation's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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.

64 


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Definition and Limitations of Internal Control over Financial Reporting

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

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

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 27, 2019

We have served as the Corporation’s auditor since 1934.  

 

  

 

65 


CONSOLIDATED STATEMENT OF INCOME

 

 

 

Note

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

Number

 

2018

 

2017

 

2016

 

 

 

 

 

(millions of dollars)

Revenues and other income

 

 

 

 

 

 

 

 

Sales and other operating revenue

 

 

279,332

 

237,162

 

200,628

 

Income from equity affiliates

7

 

7,355

 

5,380

 

4,806

 

Other income

 

 

3,525

 

1,821

 

2,680

 

 

Total revenues and other income

 

 

290,212

 

244,363

 

208,114

Costs and other deductions

 

 

 

 

 

 

 

 

Crude oil and product purchases

 

 

156,172

 

128,217

 

104,171

 

Production and manufacturing expenses

 

 

36,682

 

32,690

 

30,448

 

Selling, general and administrative expenses

 

 

11,480

 

10,649

 

10,443

 

Depreciation and depletion

9

 

18,745

 

19,893

 

22,308

 

Exploration expenses, including dry holes

 

 

1,466

 

1,790

 

1,467

 

Non-service pension and postretirement benefit expense

2, 17

 

1,285

 

1,745

 

1,835

 

Interest expense

 

 

766

 

601

 

453

 

Other taxes and duties

19

 

32,663

 

30,104

 

29,020

 

 

Total costs and other deductions

 

 

259,259

 

225,689

 

200,145

Income before income taxes

 

 

30,953

 

18,674

 

7,969

 

Income taxes

19

 

9,532

 

(1,174)

 

(406)

Net income including noncontrolling interests

 

 

21,421

 

19,848

 

8,375

 

Net income attributable to noncontrolling interests

 

 

581

 

138

 

535

Net income attributable to ExxonMobil

 

 

20,840

 

19,710

 

7,840

 

 

 

 

 

 

 

 

 

 

Earnings per common share (dollars) 

12

 

4.88

 

4.63

 

1.88

 

 

 

 

 

 

 

 

 

 

Earnings per common share - assuming dilution (dollars) 

12

 

4.88

 

4.63

 

1.88

 

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

   

 

66 


CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

21,421

 

19,848

 

8,375

Other comprehensive income (net of income taxes)

 

 

 

 

 

 

 

Foreign exchange translation adjustment

 

(5,077)

 

5,352

 

(174)

 

Adjustment for foreign exchange translation (gain)/loss

 

 

 

 

 

 

 

 

included in net income

 

196

 

234

 

-

 

Postretirement benefits reserves adjustment (excluding amortization)

 

280

 

(219)

 

493

 

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs

 

931

 

1,165

 

1,086

 

 

Total other comprehensive income

 

(3,670)

 

6,532

 

1,405

Comprehensive income including noncontrolling interests

 

17,751

 

26,380

 

9,780

 

Comprehensive income attributable to noncontrolling interests

 

174

 

693

 

668

Comprehensive income attributable to ExxonMobil

 

17,577

 

25,687

 

9,112

 

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

  

 

67 


CONSOLIDATED BALANCE SHEET

 

 

 

 

Note

 

 

 

 

 

 

 

 

Reference

 

Dec. 31

 

Dec. 31

 

 

 

 

Number

 

2018

 

2017

 

 

 

 

 

 

(millions of dollars)

Assets

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

3,042

 

3,177

 

 

Notes and accounts receivable, less estimated doubtful amounts

6

 

24,701

 

25,597

 

 

Inventories

 

 

 

 

 

 

 

 

Crude oil, products and merchandise

3

 

14,803

 

12,871

 

 

 

Materials and supplies

 

 

4,155

 

4,121

 

 

Other current assets

 

 

1,272

 

1,368

 

 

 

Total current assets

 

 

47,973

 

47,134

 

Investments, advances and long-term receivables

8

 

40,790

 

39,160

 

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

 

 

 

 

 

 

 

and depletion

9

 

247,101

 

252,630

 

Other assets, including intangibles, net

 

 

10,332

 

9,767

 

 

 

Total assets

 

 

346,196

 

348,691

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Notes and loans payable

6

 

17,258

 

17,930

 

 

Accounts payable and accrued liabilities

6

 

37,268

 

36,796

 

 

Income taxes payable

 

 

2,612

 

3,045

 

 

 

Total current liabilities

 

 

57,138

 

57,771

 

Long-term debt

14

 

20,538

 

24,406

 

Postretirement benefits reserves

17

 

20,272

 

21,132

 

Deferred income tax liabilities

19

 

27,244

 

26,893

 

Long-term obligations to equity companies

 

 

4,382

 

4,774

 

Other long-term obligations

 

 

18,094

 

19,215

 

 

 

Total liabilities

 

 

147,668

 

154,191

 

 

 

 

 

 

 

 

 

Commitments and contingencies

16

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

Common stock without par value

 

 

 

 

 

 

 

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

 

 

15,258

 

14,656

 

Earnings reinvested

 

 

421,653

 

414,540

 

Accumulated other comprehensive income

 

 

(19,564)

 

(16,262)

 

Common stock held in treasury

 

 

 

 

 

 

 

(3,782 million shares in 2018 and 3,780 million shares in 2017)

 

 

(225,553)

 

(225,246)

 

 

 

ExxonMobil share of equity

 

 

191,794

 

187,688

 

Noncontrolling interests

 

 

6,734

 

6,812

 

 

 

Total equity

 

 

198,528

 

194,500

 

 

 

Total liabilities and equity

 

 

346,196

 

348,691

 

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

   

 

68 


CONSOLIDATED STATEMENT OF CASH FLOWS 

 

 

 

 

 

Note

 

 

 

 

 

 

 

 

 

 

 

Reference

 

 

 

 

 

 

 

 

 

 

 

Number

 

2018

 

2017

 

2016

 

 

 

 

 

 

 

(millions of dollars)

Cash flows from operating activities

 

 

 

 

 

 

 

 

Net income including noncontrolling interests

 

 

21,421

 

19,848

 

8,375

 

Adjustments for noncash transactions

 

 

 

 

 

 

 

 

 

Depreciation and depletion

9

 

18,745

 

19,893

 

22,308

 

 

Deferred income tax charges/(credits)

 

 

(60)

 

(8,577)

 

(4,386)

 

 

Postretirement benefits expense

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) net payments

 

 

1,070

 

1,135

 

(329)

 

 

Other long-term obligation provisions

 

 

 

 

 

 

 

 

 

 

in excess of/(less than) payments

 

 

(68)

 

(610)

 

(19)

 

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

 

 

 

 

 

 

 

 

 

earnings of equity companies

 

 

(1,684)

 

131

 

(579)

 

Changes in operational working capital, excluding cash and debt

 

 

 

 

 

 

 

 

Reduction/(increase)

- Notes and accounts receivable

 

 

(545)

 

(3,954)

 

(2,090)

 

 

 

 

- Inventories

 

 

(3,107)

 

(1,682)

 

(388)

 

 

 

 

- Other current assets

 

 

(25)

 

(117)

 

171

 

 

Increase/(reduction)

- Accounts and other payables

 

 

2,321

 

5,104

 

915

 

Net (gain) on asset sales

5

 

(1,993)

 

(334)

 

(1,682)

 

All other items - net

 

 

(61)

 

(771)

 

(214)

 

 

Net cash provided by operating activities

 

 

36,014

 

30,066

 

22,082

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

 

(19,574)

 

(15,402)

 

(16,163)

 

Proceeds associated with sales of subsidiaries, property, plant

 

 

 

 

 

 

 

 

 

and equipment, and sales and returns of investments

 

 

4,123

 

3,103

 

4,275

 

Additional investments and advances

 

 

(1,981)

 

(5,507)

 

(1,417)

 

Other investing activities including collection of advances

 

 

986

 

2,076

 

902

 

 

Net cash used in investing activities

 

 

(16,446)

 

(15,730)

 

(12,403)

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

 

Additions to long-term debt

 

 

46

 

60

 

12,066

 

Additions to short-term debt

 

 

-

 

1,735

 

-

 

Reductions in short-term debt

 

 

(4,752)

 

(5,024)

 

(314)

 

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

 

 

 

 

 

 

 

 

 

three months or less maturity

5

 

(219)

 

2,181

 

(7,459)

 

Cash dividends to ExxonMobil shareholders

 

 

(13,798)

 

(13,001)

 

(12,453)

 

Cash dividends to noncontrolling interests

 

 

(243)

 

(184)

 

(162)

 

Changes in noncontrolling interests

 

 

146

 

(150)

 

-

 

Common stock acquired

 

 

(626)

 

(747)

 

(977)

 

Common stock sold

 

 

-

 

-

 

6

 

 

Net cash used in financing activities

 

 

(19,446)

 

(15,130)

 

(9,293)

Effects of exchange rate changes on cash

 

 

(257)

 

314

 

(434)

Increase/(decrease) in cash and cash equivalents

 

 

(135)

 

(480)

 

(48)

Cash and cash equivalents at beginning of year

 

 

3,177

 

3,657

 

3,705

Cash and cash equivalents at end of year

 

 

3,042

 

3,177

 

3,657

 

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

   

 

69 


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, 2015

 

11,612

 

412,444

 

(23,511)

 

(229,734)

 

170,811

 

5,999

 

176,810

 

Amortization of stock-based awards

 

796

 

-

 

-

 

-

 

796

 

-

 

796

 

Tax benefits related to stock-based awards

 

30

 

-

 

-

 

-

 

30

 

-

 

30

 

Other

 

(281)

 

-

 

-

 

-

 

(281)

 

-

 

(281)

 

Net income for the year

 

-

 

7,840

 

-

 

-

 

7,840

 

535

 

8,375

 

Dividends - common shares

 

-

 

(12,453)

 

-

 

-

 

(12,453)

 

(162)

 

(12,615)

 

Other comprehensive income

 

-

 

-

 

1,272

 

-

 

1,272

 

133

 

1,405

 

Acquisitions, at cost

 

-

 

-

 

-

 

(977)

 

(977)

 

-

 

(977)

 

Dispositions

 

-

 

-

 

-

 

287

 

287

 

-

 

287

Balance as of December 31, 2016

 

12,157

 

407,831

 

(22,239)

 

(230,424)

 

167,325

 

6,505

 

173,830

 

Amortization of stock-based awards

 

801

 

-

 

-

 

-

 

801

 

-

 

801

 

Other

 

(380)

 

-

 

-

 

-

 

(380)

 

(52)

 

(432)

 

Net income for the year

 

-

 

19,710

 

-

 

-

 

19,710

 

138

 

19,848

 

Dividends - common shares

 

-

 

(13,001)

 

-

 

-

 

(13,001)

 

(184)

 

(13,185)

 

Other comprehensive income

 

-

 

-

 

5,977

 

-

 

5,977

 

555

 

6,532

 

Acquisitions, at cost

 

-

 

-

 

-

 

(828)

 

(828)

 

(150)

 

(978)

 

Issued for acquisitions

 

2,078

 

-

 

-

 

5,711

 

7,789

 

-

 

7,789

 

Dispositions

 

-

 

-

 

-

 

295

 

295

 

-

 

295

Balance as of December 31, 2017

 

14,656

 

414,540

 

(16,262)

 

(225,246)

 

187,688

 

6,812

 

194,500

 

Amortization of stock-based awards

 

758

 

-

 

-

 

-

 

758

 

-

 

758

 

Other

 

(156)

 

-

 

-

 

-

 

(156)

 

436

 

280

 

Net income for the year

 

-

 

20,840

 

-

 

-

 

20,840

 

581

 

21,421

 

Dividends - common shares

 

-

 

(13,798)

 

-

 

-

 

(13,798)

 

(243)

 

(14,041)

 

Cumulative effect of accounting change

 

-

 

71

 

(39)

 

-

 

32

 

15

 

47

 

Other comprehensive income

 

-

 

-

 

(3,263)

 

-

 

(3,263)

 

(407)

 

(3,670)

 

Acquisitions, at cost

 

-

 

-

 

-

 

(626)

 

(626)

 

(460)

 

(1,086)

 

Dispositions

 

-

 

-

 

-

 

319

 

319

 

-

 

319

Balance as of December 31, 2018

 

15,258

 

421,653

 

(19,564)

 

(225,553)

 

191,794

 

6,734

 

198,528

 

 

 

 

 

 

Held in

 

 

Common Stock Share Activity

 

Issued

 

Treasury

Outstanding

 

 

 

(millions of shares)

 

 

 

 

 

 

 

 

Balance as of December 31, 2015

 

8,019

 

(3,863)

 

4,156

 

Acquisitions

 

-

 

(12)

 

(12)

 

Dispositions

 

-

 

4

 

4

Balance as of December 31, 2016

 

8,019

 

(3,871)

 

4,148

 

Acquisitions

 

-

 

(10)

 

(10)

 

Issued for acquisitions

 

-

 

96

 

96

 

Dispositions

 

-

 

5

 

5

Balance as of December 31, 2017

 

8,019

 

(3,780)

 

4,239

 

Acquisitions

 

-

 

(8)

 

(8)

 

Dispositions

 

-

 

6

 

6

Balance as of December 31, 2018

 

8,019

 

(3,782)

 

4,237

 

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

   

 

70 


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 involves exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a wide variety of specialty products.

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 2018 presentation basis.

 

1. Summary of Accounting Policies

Principles of Consolidation and Accounting for Investments

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.

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.

Investments in equity securities other than consolidated subsidiaries and equity method investments are measured at fair value with changes in fair value recognized in net income. The Corporation uses the modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in a similar investment of the same issuer.

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in “Accumulated other comprehensive income”.

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 to reflect market conditions. Revenue is recognized at the amount the Corporation expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.

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 and other operating revenue” and “Notes and accounts receivable” primarily arise from contracts with customers. Long-term receivables are primarily from non-customers. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts and are not significant.

 

 

71 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Income and Other Taxes

The Corporation excludes from the Consolidated Statement of Income certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of governmental authorities. Similar taxes, for which the Corporation is not considered to be an agent for the government, are reported on a gross basis (included in both “Sales and other operating revenue” and “Other taxes and duties”).

The Corporation accounts for U.S. tax on global intangible low-taxed income as an income tax expense in the period in which it is incurred. We have elected not to adopt an option provided by the Financial Accounting Standards Board Update, Income Statement – Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The option allowed the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act.

Derivative Instruments

The Corporation may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, foreign currency exchange rates and interest rates that arise from existing assets, liabilities and forecasted transactions. All derivative instruments are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. All gains and losses from derivative instruments for which the Corporation does not apply hedge accounting are immediately recognized in earnings. We may designate derivatives as fair value or cash flow hedges. For fair value hedges, the gain or loss from derivative instruments and the offsetting gain or loss from the hedged item are recognized in earnings. For cash flow hedges, the effective portion of the gain or loss from the derivative instrument is initially reported as a component of other comprehensive income and subsequently reclassified into earnings in the period that the forecasted transaction affects earnings, and the ineffective portion of the gain or loss from the derivative instrument is recognized immediately in earnings.

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 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

Cost Basis. 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.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization 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.

 

 

72 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 the unit-of-production rates based on the amount of proved developed reserves of oil and gas 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 method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the Corporation uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.

To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes.

Investments in refinery, chemical process, and lubes basestock manufacturing equipment are generally depreciated on a straight‑line basis over a 25-year life. Service station buildings and fixed improvements generally are depreciated over a 20-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

·          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.

Asset valuation analyses performed as part of its asset management program and other profitability reviews assist the Corporation in assessing whether events or changes in circumstances indicate 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 an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technology and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the vast majority of the Corporation’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and production costs. During the lifespan of these major assets, the Corporation expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the Corporation considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.

When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the Corporation’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil price, natural gas price or margin ranges, the Corporation may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, an indicator of potential impairment for certain assets.

 

 

73 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In the Upstream, the standardized measure of discounted cash flows included in the Supplemental Information on Oil and Gas Exploration and Production activities is required to use prices based on the average of first-of-month prices. These prices represent discrete points in time and could be higher or lower than the Corporation’s long-term price assumptions which are used for impairment assessments. The Corporation believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.

If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, 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. Cash flows used in recoverability assessments are based on the Corporation’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the Corporation’s assumptions of future capital allocations, crude oil and natural gas commodity prices, refining and chemical margins, volumes, costs, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

An asset group is impaired if its estimated undiscounted cash flows are less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. Fair value is based on market prices if an active market exists for the asset group, or discounted cash flows using a discount rate commensurate with the risk. 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.

 

Other. 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.  

74 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

2. Accounting Changes

  

Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s Standard, Revenue from Contracts with Customers (Topic 606), as amended. The standard establishes a single revenue recognition model for all contracts with customers, eliminates industry and transaction specific requirements, and expands disclosure requirements. The standard was adopted using the Modified Retrospective method, under which prior year results are not restated, but supplemental information is provided for any material impacts of the standard on 2018 results. The adoption of the standard did not have a material impact on any of the lines reported in the Corporation’s financial statements. The cumulative effect of adoption of the standard was de minimis. The Corporation did not elect any practical expedients that require disclosure.

Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s Update, Financial Instruments   Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The standard requires investments in equity securities other than consolidated subsidiaries and equity method investments to be measured at fair value with changes in the fair value recognized through net income. The Corporation elected a modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. The cumulative effect adjustment related to the adoption of this standard increased opening 2018 retained earnings $47 million.

Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s Update, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The update requires separate presentation of the service cost component from other components of net benefit costs. The other components are reported in a new line on the Corporation’s Statement of Income, “Non-service pension and postretirement benefit expense”. The Corporation elected to use the practical expedient which uses the amounts disclosed in the pension and other postretirement benefit plan note for the prior comparative periods as the estimation basis for applying the retrospective presentation requirements, as it is impracticable to determine the amounts capitalized in those periods. Beginning in 2018, the other components of net benefit costs are included in the Corporate and financing segment. The estimated after-tax impact from the change in segmentation is an increase in Corporate and financing expenses of about $450 million for 2018. The increase in the Corporate and financing expenses is offset by lower expenses across the operating segments. Additionally, only the service cost component of net benefit costs is eligible for capitalization in situations where it is otherwise appropriate to capitalize employee costs in connection with the construction or production of an asset.

The impact of the retrospective presentation change on ExxonMobil's Consolidated Statement of Income for 2017 and 2016 is shown below.

 

 

 

 

 

 

 

 

 

2017

 

2016

 

 

 

As Reported

 

Change

 

As Adjusted

 

As Reported

 

Change

 

As Adjusted

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and manufacturing expenses

34,128

 

(1,438)

 

32,690

 

31,927

 

(1,479)

 

30,448

Selling, general and administrative expenses

10,956

 

(307)

 

10,649

 

10,799

 

(356)

 

10,443

Non-service pension and postretirement benefit expense

-

 

1,745

 

1,745

 

-

 

1,835

 

1,835

75 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Effective January 1, 2019, the Corporation adopted the Financial Accounting Standards Board’s Standard, Leases (Topic 842), as amended. The standard requires all leases to be recorded on the balance sheet as a right of use asset and a lease liability. The Corporation used a transition method that applies the new lease standard at January 1, 2019, and recognizes any cumulative-effect adjustments to the opening balance of 2019 retained earnings. The Corporation applied a policy election to exclude short-term leases from balance sheet recognition and also elected certain practical expedients at adoption. As permitted under these expedients the Corporation did not reassess whether existing contracts are or contain leases, the lease classification for any existing leases, initial direct costs for any existing lease and whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease. At January 1, 2019, the operating lease liability is estimated to be in the range of $3.3 billion and the operating lease right of use asset is estimated to be in the range of $4.3 billion, including about $1.0 billion related to prepaid leases. The cumulative effect adjustment is expected to be de minimis.

  



3. Miscellaneous Financial Information

Research and development expenses totaled $1,116 million in 2018, $1,063 million in 2017, and $1,058 million in 2016.

Net income included before‑tax aggregate foreign exchange transaction losses of $138 million in 2018, and gains of $6 million and $29 million in 2017 and 2016, respectively.

In 2018, 2017 and 2016, net income included a gain of $107 million, and losses of $10 million, and $295 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 $8.2 billion and $10.8 billion at December 31, 2018, and 2017, respectively.

Crude oil, products and merchandise as of year-end 2018 and 2017 consist of the following:

 

 

 

 

2018

 

2017

 

 

 

    (millions of dollars)

 

 

 

 

 

 

Crude oil

 

4,783

 

4,635

Petroleum products

 

5,666

 

4,333

Chemical products

 

3,821

 

3,283

Gas/other

 

533

 

620

 

Total

 

14,803

 

12,871

76 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

4.     Other Comprehensive Income Information

 

 

 

 

Cumulative

 

Post-

 

 

 

 

 

Foreign

 

retirement

 

 

 

 

 

Exchange

 

Benefits

 

 

ExxonMobil Share of Accumulated Other

Translation

 

Reserves

 

 

Comprehensive Income

Adjustment

 

Adjustment

 

Total

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Balance as of December 31, 2015

(14,170)

 

 

(9,341)

 

 

(23,511)

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(331)

 

 

552

 

 

221

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

comprehensive income

-

 

 

1,051

 

 

1,051

Total change in accumulated other comprehensive income

(331)

 

 

1,603

 

 

1,272

Balance as of December 31, 2016

(14,501)

 

 

(7,738)

 

 

(22,239)

 

 

 

 

 

 

 

 

 

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

4,879

 

 

(170)

 

 

4,709

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

comprehensive income

140

 

 

1,128

 

 

1,268

Total change in accumulated other comprehensive income

5,019

 

 

958

 

 

5,977

Balance as of December 31, 2017

(9,482)

 

 

(6,780)

 

 

(16,262)

 

 

 

 

 

 

 

 

 

 

Current period change excluding amounts reclassified

 

 

 

 

 

 

 

 

from accumulated other comprehensive income

(4,595)

 

 

201

 

 

(4,394)

Amounts reclassified from accumulated other

 

 

 

 

 

 

 

 

comprehensive income

196

 

 

896

 

 

1,092

Total change in accumulated other comprehensive income

(4,399)

 

 

1,097

 

 

(3,302)

Balance as of December 31, 2018

(13,881)

 

 

(5,683)

 

 

(19,564)

 

Amounts Reclassified Out of Accumulated Other

 

 

 

 

 

 

Comprehensive Income - Before-tax Income/(Expense)

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

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

 

 

 

 

 

 

 

(Statement of Income line: Other income)

 

(196)

 

(234)

 

-

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

 

adjustment included in net periodic benefit costs

 

 

 

 

 

 

 

(Statement of Income line: Non-service pension and postretirement

 

 

 

 

 

 

 

benefit expense)

 

(1,208)

 

(1,656)

 

(1,531)

                 

 

Income Tax (Expense)/Credit For

 

 

 

 

 

Components of Other Comprehensive Income

2018

 

2017

 

2016

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

Foreign exchange translation adjustment

32

 

67

 

43

Postretirement benefits reserves adjustment (excluding amortization)

(193)

 

201

 

(247)

Amortization and settlement of postretirement benefits reserves

 

 

 

 

 

 

adjustment included in net periodic benefit costs

(277)

 

(491)

 

(445)

Total

(438)

 

(223)

 

(649)

77 


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 2018, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows includes before-tax amounts from the sale of service stations in Germany, the divestment of the Augusta refinery in Italy, and the sale of an undeveloped Upstream property in Australia. For 2017, the number includes before-tax amounts from the sale of service stations in multiple countries, Upstream asset transactions in the U.S., and the sale of ExxonMobil’s operated Upstream business in Norway. For 2016, the number includes before-tax amounts from the sale of service stations in Canada, the sale of Upstream properties in the U.S., and the sale of aviation fueling operations across multiple countries. These net gains are reported in “Other income” on the Consolidated Statement of Income.

In 2018, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated Statement of Cash Flows includes a net $275 million addition of commercial paper with maturity over three months. The gross amount issued was $4.0 billion, while the gross amount repaid was $3.8 billion. In 2017, the number includes a net $121 million repayment of commercial paper with maturity over three months. The gross amount issued was $3.6 billion, while the gross amount repaid was $3.7 billion. In 2016, the number includes a net $608 million addition of commercial paper with maturity over three months. The gross amount issued was $3.9 billion, while the gross amount repaid was $3.3 billion.

In 2017, the Corporation completed the acquisitions of InterOil Corporation, mostly unproved properties in Papua New Guinea, for $2.7 billion and of companies that own mostly unproved oil and gas properties in the Permian Basin and other assets for $6.2 billion. These transactions included a significant noncash component associated with the issuance of a total of 96 million shares of Exxon Mobil Corporation common stock in acquisition consideration, having a total acquisition date value of $7.8 billion.

 

 

2018

 

2017

 

2016

 

 

(millions of dollars)

 

 

 

 

 

 

 

Cash payments for interest

 

955

 

1,132

 

818

 

 

 

 

 

 

 

Cash payments for income taxes

 

9,294

 

7,510

 

4,214



6. Additional Working Capital Information

 

 

 

 

Dec. 31

 

Dec. 31

 

 

 

 

2018

 

2017

 

 

 

 

(millions of dollars)

Notes and accounts receivable

 

 

 

 

 

Trade, less reserves of $61 million and $72 million

 

19,638

 

21,274

 

Other, less reserves of $339 million and $539 million

 

5,063

 

4,323

 

 

Total

 

24,701

 

25,597

 

 

 

 

 

 

 

Notes and loans payable

 

 

 

 

 

Bank loans

 

325

 

115

 

Commercial paper

 

12,863

 

13,049

 

Long-term debt due within one year

 

4,070

 

4,766

 

 

Total

 

17,258

 

17,930

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

 

 

 

 

Trade payables

 

21,063

 

21,701

 

Payables to equity companies

 

6,863

 

5,453

 

Accrued taxes other than income taxes

 

3,280

 

3,311

 

Other

 

6,062

 

6,331

 

 

Total

 

37,268

 

36,796

 

The Corporation has short-term committed lines of credit of $5.3 billion which were unused as of December 31, 2018. These lines are available for general corporate purposes.

The weighted-average interest rate on short-term borrowings outstanding was 2.4 percent and 1.3 percent at December 31, 2018, and 2017, respectively.

78 


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 in Europe; liquefied natural gas (LNG) operations and transportation of crude oil in Africa; and exploration, production, LNG operations, and the manufacture and sale of petroleum and petrochemical products in Asia and the Middle East. Also included are several refining, petrochemical manufacturing and marketing ventures.

The share of total equity company revenues from sales to ExxonMobil consolidated companies was 14 percent, 15 percent and 14 percent in the years 2018, 2017 and 2016, respectively.

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” on the Consolidated Statement of Income.

 

 

 

 

2018

 

2017

 

2016

Equity Company

 

 

ExxonMobil

 

ExxonMobil

 

      ExxonMobil

Financial Summary

 

Total

 

Share

 

Total

 

Share

 

Total

 

Share

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total revenues

 

112,938

 

34,539

 

94,791

 

29,340

 

80,247

 

24,668

Income before income taxes

 

37,203

 

10,482

 

29,748

 

8,498

 

22,269

 

6,509

Income taxes

 

11,568

 

3,151

 

8,421

 

2,236

 

6,334

 

1,701

 

Income from equity affiliates

 

25,635

 

7,331

 

21,327

 

6,262

 

15,935

 

4,808

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets

 

38,670

 

13,394

 

35,367

 

12,050

 

34,412

 

11,392

Long-term assets

 

128,830

 

35,970

 

122,221

 

34,931

 

109,646

 

32,357

 

Total assets

 

167,500

 

49,364

 

157,588

 

46,981

 

144,058

 

43,749

Current liabilities

 

27,324

 

7,606

 

21,725

 

6,348

 

20,507

 

5,765

Long-term liabilities

 

56,913

 

17,109

 

59,736

 

17,056

 

62,110

 

17,288

 

Net assets

 

83,263

 

24,649

 

76,127

 

23,577

 

61,441

 

20,696

 

 

 

 

 

 

 

 

 

 

 

 

 

 

79 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

A list of significant equity companies as of December 31, 2018, together with the Corporation’s percentage ownership interest, is detailed below:

 

 

Percentage

 

 

 

 

 

Ownership

 

 

 

 

 

Interest

 

 

 

 

Upstream

 

 

 

 

 

Aera Energy LLC

48

 

 

 

 

Barzan Gas Company Limited

7

 

 

 

 

BEB Erdgas und Erdoel GmbH & Co. KG

50

 

 

 

 

Cameroon Oil Transportation Company S.A.

41

 

 

 

 

Caspian Pipeline Consortium - Kazakhstan

8

 

 

 

 

Cross Timbers Energy, LLC

50

 

 

 

 

Golden Pass LNG Terminal LLC

18

 

 

 

 

Marine Well Containment Company LLC

10

 

 

 

 

Mozambique Rovuma Venture, S.p.A.

36

 

 

 

 

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

 

 

 

 

Permian Express Partners LLC

12

 

 

 

 

Saudi Aramco Mobil Refinery Company Ltd.

50

 

 

 

 

 

 

 

 

 

 

Chemical

 

 

 

 

 

Al-Jubail Petrochemical Company

50

 

 

 

 

Gulf Coast Growth Ventures LLC

50

 

 

 

 

Infineum Italia s.r.l.

50

 

 

 

 

Infineum Singapore Pte. Ltd.

50

 

 

 

 

Infineum USA L.P.

50

 

 

 

 

Saudi Yanbu Petrochemical Co.

50

 

 

 

80 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

8. Investments, Advances and Long-Term Receivables

 

 

 

 

Dec. 31,

 

Dec. 31,

 

 

 

 

2018

 

2017

 

 

 

 

(millions of dollars)

Equity method company investments and advances

 

 

 

 

 

Investments

 

26,382

 

24,354

 

Advances

 

8,608

 

9,112

 

 

Total equity method company investments and advances

 

34,990

 

33,466

Equity securities carried at fair value and other investments at adjusted cost basis (1) 

 

210

 

174

Long-term receivables and miscellaneous, net of reserves of $ 5,471 million and $5,432 million

 

5,590

 

5,520

 

 

Total

 

40,790

 

39,160

 

 

 

 

 

 

 

(1) Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s Update, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The portion of unrealized gains and losses recognized during the reporting period on equity securities still held at December 31, 2018, and the carrying value of equity securities without readily determinable fair values at December 31, 2018, were not significant to the Corporation.



9. Property, Plant and Equipment and Asset Retirement Obligations

 

 

 

 

December 31, 2018

 

December 31, 2017

Property, Plant and Equipment

 

Cost

 

Net

 

Cost

 

Net

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

Upstream

 

372,791

 

194,662

 

371,904

 

200,291

Downstream

 

48,241

 

21,448

 

50,343

 

21,732

Chemical

 

39,008

 

20,551

 

37,966

 

20,117

Other

 

17,150

 

10,440

 

16,972

 

10,490

 

Total

 

477,190

 

247,101

 

477,185

 

252,630

 

The Corporation has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and relies in part on the Corporation’s planning and budgeting cycle. In 2018, the Corporation identified a number of situations where events or changes in circumstances indicated that the carrying value of certain long-lived assets, mainly in North America, may not be recoverable. Accordingly, impairment assessments were performed which indicated that certain asset groups assessed have future undiscounted cash flow estimates that do not recover their carrying values. The Corporation’s 2018 results include before-tax charges of $0.7 billion to reduce the carrying value of those assets to fair value. In 2017 and 2016, the Corporation recognized before-tax impairment charges of $2.0 billion and $3.6 billion, respectively.

81 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The assessment of fair values required the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair values included estimates of both proved and unproved reserves, future commodity prices which were consistent with the average of third-party industry experts and government agencies, drilling and development costs, a range of discount rates depending on the characteristics of the asset group, and comparable market transactions. Factors which could put further assets at risk of impairment in the future include reductions in the Corporation’s long-term price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases. However, 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 the existence or range of any potential future impairment charges related to the Corporation’s long-lived assets.

Accumulated depreciation and depletion totaled $230,089 million at the end of 2018 and $224,555 million at the end of 2017. Interest capitalized in 2018, 2017 and 2016 was $652 million, $749 million and $708 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:

 

 

 

 

2018

 

2017

 

 

 

(millions of dollars)

 

 

 

 

 

 

Beginning balance

 

12,705

 

13,243

 

Accretion expense and other provisions

 

681

 

780

 

Reduction due to property sales

 

(333)

 

(906)

 

Payments made

 

(600)

 

(730)

 

Liabilities incurred

 

46

 

128

 

Foreign currency translation

 

(481)

 

611

 

Revisions

 

85

 

(421)

Ending balance

 

12,103

 

12,705

 

The long-term Asset Retirement Obligations were $11,185 million and $11,928 million at December 31, 2018, and 2017, respectively, and are included in Other long-term obligations.  

82 


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:

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Balance beginning at January 1

 

3,700

 

4,477

 

4,372

 

Additions pending the determination of proved reserves

 

564

 

906

 

180

 

Charged to expense

 

(7)

 

(1,205)

 

(111)

 

Reclassifications to wells, facilities and equipment based on the

 

 

 

 

 

 

 

 

determination of proved reserves

 

(48)

 

(497)

 

-

 

Divestments/Other

 

(49)

 

19

 

36

Ending balance at December 31

 

4,160

 

3,700

 

4,477

Ending balance attributed to equity companies included above

 

306

 

306

 

707

 

Period end capitalized suspended exploratory well costs:

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Capitalized for a period of one year or less

 

564

 

906

 

180

 

Capitalized for a period of between one and five years

 

2,028

 

1,345

 

2,981

 

Capitalized for a period of between five and ten years

 

1,150

 

1,064

 

911

 

Capitalized for a period of greater than ten years

 

418

 

385

 

405

Capitalized for a period greater than one year - subtotal

 

3,596

 

2,794

 

4,297

 

 

Total

 

4,160

 

3,700

 

4,477

 

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 only exploratory well costs capitalized for a period of one year or less and those that have had exploratory well costs capitalized for a period of greater than one year.

 

 

 

 

2018

 

2017

 

2016

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

 

 

 

 

 

 

of one year or less

 

6

 

11

 

2

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

 

 

 

 

 

 

of greater than one year

 

52

 

46

 

58

 

 

Total

 

58

 

57

 

60

 

Of the 52 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2018, 12 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 40 projects are those with completed exploratory activity progressing toward development.

83 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The table below provides additional detail for those 40 projects, which total $2,543 million.

  

 

 

 

Years Wells

 

 

 

Dec. 31,

Drilled /

 

Country/Project

2018

Acquired

Comment

 

(millions of dollars)

 

Angola

 

 

 

 

 

 - AB32 Central NE Hub

 

69

 

2006 - 2014

 Evaluating development plan for tieback to existing production facilities.

 - Kaombo Split Hub

 

20

 

2005 - 2006

 Evaluating development plan to tie into planned production facilities.

   Phase 2

 

 

 

 

 

Argentina

 

 

 

 

 

 - La Invernada

 

72

 

2014

 Evaluating development plan to tie into planned infrastructure.

Australia

 

 

 

 

 

 - East Pilchard

 

7

 

2001

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

 

 

 

 

 

 planned infrastructure.

 - Gorgon Area Ullage

 

318

 

1994 - 2015

 Evaluating development plans to tie into existing LNG facilities.

 - SE Longtom

 

11

 

2010

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

 

 

 

 

 

 infrastructure. 

 - SE Remora

 

33

 

2010

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

 

 

 

 

 

 infrastructure. 

Guyana

 

 

 

 

 

 - Liza Phase 2

 

37

 

2017

 Continuing development plan discussions with the government.

Iraq

 

 

 

 

 

 - Kurdistan Pirmam

 

109

 

2015

 Evaluating commercialization alternatives, while waiting for government

 

 

 

 

 

 approval to enter Gas Holding Period.

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/progressing development alternatives, while continuing

 

 

 

 

 

 discussions with the government regarding development plan.

Mozambique

 

 

 

 

 

 - Rovuma LNG Future

 

120

 

2017

 Evaluating/progressing development plan to tie into planned LNG facilities.

    Non-Straddling Train

 

 

 

 

 

 - Rovuma LNG Phase 1

 

150

 

2017

 Progressing development plan to tie into planned LNG facilities.

 - Rovuma LNG Unitized

 

35

 

2017

 Evaluating/progressing development plan to tie into planned LNG facilities.

    Trains

 

 

 

 

 

Nigeria

 

 

 

 

 

 - Bolia

 

15

 

2002 - 2006

 Evaluating development plan, while continuing discussions with the

 

 

 

 

 

 government regarding regional hub strategy.

 - Bonga North

 

34

 

2004 - 2009

 Evaluating/progressing development plan for tieback to existing/planned

 

 

 

 

 

 infrastructure. 

 - 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.

 - OML 138 Ukot SS

 

13

 

2015

 Evaluating development plan for tieback to existing production facilities.

 - OML 138 Ukot SW

 

41

 

2014

 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)

 

10

 

2001 - 2002

 Evaluating and pursuing development of several additional discoveries.

84 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Years Wells

 

 

 

Dec. 31,

Drilled /

 

Country/Project

2018

Acquired

Comment

 

(millions of dollars)

 

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 (6 projects)

 

23

 

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.

 - Papua LNG

 

246

 

2017

 Evaluating/progressing development plans.

Republic of Congo

 

 

 

 

 

 - Mer Tres Profonde Sud

 

56

 

2000 - 2007

 Evaluating development alternatives, while continuing discussions with the

 

 

 

 

 

 government regarding development plan.

Romania

 

 

 

 

 

 - Neptun Deep

 

536

 

2012 - 2016

 Continuing discussions with the government regarding development plan.

Vietnam

 

 

 

 

 

 - Blue Whale

 

296

 

2011 - 2015

 Evaluating/progressing development plans.

Total 2018 (40 projects)

 

2,543

 

 

 



11. Leased Facilities

At December 31, 2018, the Corporation and its consolidated subsidiaries held noncancelable operating leases and charters covering drilling equipment, tankers and other assets with minimum undiscounted lease commitments totaling $6,112 million as indicated in the table. Estimated related sublease rental income from noncancelable subleases totals $22 million.

 

 

 

Lease Payments

  

 

Under Minimum Commitments

 

 

 

Drilling Rigs

 

 

 

 

 

and Related

 

 

 

 

 

Equipment

Other

 

Total

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

2019

 

 

222

 

934

 

1,156

2020

 

 

166

 

819

 

985

2021

 

 

107

 

658

 

765

2022

 

 

43

 

506

 

549

2023

 

 

32

 

422

 

454

2024 and beyond

 

 

53

 

2,150

 

2,203

     Total

 

 

623

 

5,489

 

6,112

 

Net rental cost under both cancelable and noncancelable operating leases incurred during 2018, 2017 and 2016 were as follows:

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

Rental cost

 

 

 

 

 

 

 

Drilling rigs and related equipment

 

723

 

792

 

1,274

 

Other (net of sublease rental income)

 

1,992

 

1,826

 

1,817

 

 

Total

 

2,715

 

2,618

 

3,091

85 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

12. Earnings Per Share

 

Earnings per common share

 

2018

 

2017

 

2016

 

 

 

 

 

 

 

Net income attributable to ExxonMobil (millions of dollars)

 

20,840

 

19,710

 

7,840

 

 

 

 

 

 

 

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

 

4,270

 

4,256

 

4,177

 

 

 

 

 

 

 

Earnings per common share (dollars) (1) 

 

4.88

 

4.63

 

1.88

 

 

 

 

 

 

 

Dividends paid per common share (dollars)

 

3.23

 

3.06

 

2.98

 

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

 

13. Financial Instruments and Derivatives

Financial Instruments. The estimated fair value of financial instruments at December 31, 2018, and the related hierarchy level for the fair value measurement is as follows:

 

 

 

 

 

At December 31, 2018

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total Gross Assets

&

Liabilities

 

Effect of Counterparty Netting

 

Effect of Collateral Netting

 

Difference in Carrying Value and Fair Value

 

Net Carrying Value Presented on the Balance Sheet

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets (1) 

 

297

 

-

 

-

 

297

 

(151)

 

(146)

 

-

 

-

 

Advances to/receivables

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

from equity companies (2)(7) 

 

-

 

2,100

 

6,293

 

8,393

 

-

 

-

 

215

 

8,608

 

Other long-term

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

financial assets (3) 

 

848

 

-

 

974

 

1,822

 

-

 

-

 

112

 

1,934

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative liabilities (4) 

 

151

 

-

 

-

 

151

 

(151)

 

-

 

-

 

-

 

Long-term debt (5) 

 

19,029

 

117

 

4

 

19,150

 

-

 

-

 

85

 

19,235

 

Long-term obligations

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

to equity companies (7) 

 

-

 

-

 

4,330

 

4,330

 

-

 

-

 

52

 

4,382

 

Other long-term

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

financial liabilities (6) 

 

-

 

-

 

1,046

 

1,046

 

-

 

-

 

(3)

 

1,043

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Included in the Balance Sheet line: Notes and accounts receivable, less estimated doubtful amounts

(2) Included in the Balance Sheet line: Investments, advances and long-term receivables

(3) Included in the Balance Sheet lines: Investments, advances and long-term receivables and Other assets, including intangibles, net

(4) Included in the Balance Sheet line: Accounts payable and accrued liabilities

(5) Excluding capitalized lease obligations

(6) Included in the Balance Sheet line: Other long-term obligations

(7) Advances to/receivables from equity companies and long-term obligations to equity companies are mainly designated as hierarchy level 3 inputs. The fair value is calculated by discounting the remaining obligations by a rate consistent with the credit quality and industry of the equity company.

The estimated fair value of total long-term debt, excluding capitalized lease obligations, was $23.7 billion at December 31, 2017, as compared to recorded book values of $23.1 billion at December 31, 2017.

 

86 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 commodity prices, currency rates and interest rates. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes. The Corporation’s commodity derivatives are not accounted for under hedge accounting. At times, the Corporation also enters into forward currency and interest rate derivatives, none of which are material to the Corporation’s financial position as of December 31, 2018 and 2017, or results of operations for the years ended 2018, 2017 and 2016.

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 carrying values of derivative instruments on the consolidated balance sheet, at December 31, 2017, were gross assets of $25 million, gross liabilities of ($63) million and collateral receivable of $94 million.

 

At December 31, 2018, the net notional long/(short) position of derivative instruments was (19) million barrels for crude oil and was (9) million barrels for products.

 

Realized and unrealized gains/(losses) on derivative instruments that were recognized in the Consolidated Statement of Income are included in the following lines on a before-tax basis:

 

 

 

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue

 

 

130

 

6

 

(12)

Crude oil and product purchases

 

 

(120)

 

(105)

 

(69)

 

 

Total

 

 

10

 

(99)

 

(81)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

87 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

14. Long-Term Debt

At December 31, 2018, long-term debt consisted of $19,940 million due in U.S. dollars and $598 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 $4,070 million, which matures within one year and is included in current liabilities. The amounts of long-term debt, including capitalized lease obligations, maturing in each of the four years after December 31, 2019, in millions of dollars, are: 2020 – $1,639; 2021 – $2,571; 2022 – $1,841; and 2023 – $1,304. At December 31, 2018, the Corporation’s unused long-term credit lines were $0.2 billion.

Summarized long-term debt at year-end 2018 and 2017 are shown in the table below:

 

 

 

 

Average 

 

 

 

 

 

 

 

 

 

Rate (1)

 

2018

 

2017

 

 

 

      (millions of dollars)

 

 

Exxon Mobil Corporation

 

 

 

 

 

 

 

 

1.819% notes due 2019

 

 

-

 

1,750

 

 

 

1.708% notes due 2019

 

 

-

 

1,250

 

 

 

Floating-rate notes due 2019 (Issued 2014)

  

 

-

 

500

 

 

 

Floating-rate notes due 2019 (Issued 2016)

  

 

-

 

250

 

 

 

1.912% notes due 2020

 

 

1,500

 

1,500

 

 

 

2.222% notes due 2021

 

 

2,500

 

2,500

 

 

 

2.397% notes due 2022

 

 

1,150

 

1,150

 

 

 

Floating-rate notes due 2022

2.502%

 

500

 

500

 

 

 

2.726% notes due 2023

 

 

1,250

 

1,250

 

 

 

3.176% notes due 2024

 

 

1,000

 

1,000

 

 

 

2.709% notes due 2025

 

 

1,750

 

1,750

 

 

 

3.043% notes due 2026

 

 

2,500

 

2,500

 

 

 

3.567% notes due 2045

 

 

1,000

 

1,000

 

 

 

4.114% notes due 2046

 

 

2,500

 

2,500

 

 

 

 

  

 

 

 

 

 

 

 

XTO Energy Inc. (2) 

 

 

 

 

 

 

 

 

6.100% senior notes due 2036

 

 

195

 

195

 

 

 

6.750% senior notes due 2037

 

 

299

 

302

 

 

 

6.375% senior notes due 2038

 

 

230

 

232

 

 

 

 

 

 

 

 

 

 

 

 

Mobil Corporation

 

 

 

 

 

 

 

 

8.625% debentures due 2021

 

 

250

 

250

 

 

 

 

 

 

 

 

 

 

 

 

Industrial revenue bonds due 2019-2051

1.334%

 

2,513

 

2,559

 

 

Other U.S. dollar obligations

  

 

102

 

162

 

 

Other foreign currency obligations

  

 

38

 

34

 

 

Capitalized lease obligations

9.440%

 

1,303

 

1,327

 

 

Debt issuance costs

 

 

(42)

 

(55)

 

 

 

 

Total long-term debt

 

 

20,538

 

24,406

 

 

(1)   Average effective interest rate for debt and average imputed interest rate for capitalized leases at December 31, 2018.

(2)   Includes premiums of $97 million in 2018 and $102 million in 2017.

88 


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 awards. 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 2018, remaining shares available for award under the 2003 Incentive Program were 82 million.  

Restricted Stock and Restricted Stock Units. Awards totaling 8,771 thousand, 8,916 thousand, and 9,583 thousand of restricted (nonvested) common stock units were granted in 2018, 2017 and 2016, 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 or units settled in 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, 2018.

 

2018

 

 

 

 

Weighted Average

 

 

 

 

Grant-Date

Restricted stock and units outstanding

Shares

 

 

Fair Value per Share

 

(thousands)

 

 

(dollars)

 

 

 

 

 

 

 

Issued and outstanding at January 1

41,078

 

 

 

86.34

 

2017 award issued in 2018

8,910

 

 

 

81.89

 

Vested

(9,347)

 

 

 

81.14

 

Forfeited

(260)

 

 

 

85.72

 

Issued and outstanding at December 31

40,381

 

 

 

86.56

 

 

 

 

 

 

 

 

Value of restricted stock units

 

2018

 

2017

 

2016

Grant price (dollars)

 

77.66

 

81.89

 

87.70

 

 

 

 

 

 

 

Value at date of grant:

 

(millions of dollars)

Units settled in stock

 

620

 

667

 

771

Units settled in cash

 

61

 

63

 

69

Total value

 

681

 

730

 

840

 

As of December 31, 2018, there was $1,899 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.4 years. The compensation cost charged against income for the restricted stock and restricted stock units was $774 million, $856 million and $880 million for 2018, 2017 and 2016, respectively. The income tax benefit recognized in income related to this compensation expense was $42 million, $78 million and $80 million for the same periods, respectively. The fair value of shares and units vested in 2018, 2017 and 2016 was $722 million, $826 million and $851 million, respectively. Cash payments of $61 million, $64 million and $67 million for vested restricted stock units settled in cash were made in 2018, 2017 and 2016, respectively.

89 


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, 2018, 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.

 

 

 

 

 

 

 

December 31, 2018

 

 

 

 

 

Equity Company

Other Third-Party

 

 

 

 

 

Obligations (1) 

Obligations

 

Total

 

 

 

 

 

 

(millions of dollars)

 

 

Guarantees

 

 

 

 

 

 

 

 

 

Debt-related

 

537

 

 

71

 

 

608

 

Other

 

850

 

 

4,380

 

 

5,230

 

 

Total

 

1,387

 

 

4,451

 

 

5,838

 

 

 

 

 

 

 

 

 

 

 

(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.

In accordance with a Venezuelan nationalization decree issued in February 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil 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. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.

ExxonMobil collected awards of $908 million in an arbitration against PdVSA under the rules of the International Chamber of Commerce in respect of an indemnity related to the Cerro Negro Project and $260 million in an arbitration for compensation due for the La Ceiba Project and for export curtailments at the Cerro Negro Project under rules of International Centre for Settlement of Investment Disputes (ICSID). An ICSID arbitration award relating to the Cerro Negro Project’s expropriation ($1.4 billion) was annulled based on a determination that a prior Tribunal failed to adequately explain why the cap on damages in the indemnity owed by PdVSA did not affect or limit the amount owed for the expropriation of the Cerro Negro Project. ExxonMobil filed a new claim seeking to restore the original award of damages for the Cerro Negro Project with ICSID on September 26, 2018.

The net impact of this matter 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.

 

 

90 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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. On July 22, 2016, the Court of Appeal upheld the decision of the lower court setting aside the award. On October 21, 2016, the Contractors appealed the decision to the Supreme Court of Nigeria. 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. Following dismissal by this court, the Contractors appealed to the Nigerian Court of Appeal in June 2016. 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. 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.

91 


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

 

 

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

 

 

(percent)

Weighted-average assumptions used to determine

 

 

 

 

 

 

 

 

 

 

 

 

benefit obligations at December 31

 

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

4.40

 

3.80

 

3.00

 

2.80

 

4.40

 

3.80

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

4.30

 

4.30

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(millions of dollars)

Change in benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

 

Benefit obligation at January 1

 

19,310

 

19,960

 

27,963

 

25,196

 

8,100

 

7,800

 

Service cost

 

819

 

784

 

608

 

596

 

152

 

129

 

Interest cost

 

721

 

798

 

754

 

772

 

301

 

317

 

Actuarial loss/(gain)

 

(957)

 

733

 

(1,034)

 

250

 

(630)

 

231

 

Benefits paid (1) (2)

 

(1,715)

 

(2,964)

 

(1,284)

 

(1,291)

 

(528)

 

(543)

 

Foreign exchange rate changes

 

-

 

-

 

(1,664)

 

2,484

 

(49)

 

40

 

Amendments, divestments and other

 

(4)

 

(1)

 

35

 

(44)

 

125

 

126

Benefit obligation at December 31

 

18,174

 

19,310

 

25,378

 

27,963

 

7,471

 

8,100

Accumulated benefit obligation at December 31

 

14,683

 

15,557

 

23,350

 

25,557

 

-

 

-

 

(1)   Benefit payments for funded and unfunded plans.

(2)   For 2018 and 2017, other postretirement benefits paid are net of $13 million and $16 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 effective discount rate determined by use of a yield curve based on high-quality, noncallable bonds applied to the estimated cash outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using a spot yield curve of high-quality, local-currency-denominated bonds at an average maturity approximating that of the liabilities.

The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 4.5 percent in 2020 and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $74 million and the postretirement benefit obligation by $776 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $56 million and the postretirement benefit obligation by $620 million.

 

 

 

 

Pension Benefits

 

Other Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

 

 

(millions of dollars)

Change in plan assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair value at January 1

 

12,782

 

12,793

 

21,461

 

19,043

 

427

 

411

 

Actual return on plan assets

 

(710)

 

1,831

 

(15)

 

1,442

 

(13)

 

40

 

Foreign exchange rate changes

 

-

 

-

 

(1,320)

 

1,776

 

-

 

-

 

Company contribution

 

491

 

619

 

438

 

440

 

30

 

34

 

Benefits paid (1) 

 

(1,429)

 

(2,461)

 

(903)

 

(902)

 

(58)

 

(58)

 

Other

 

-

 

-

 

(175)

 

(338)

 

-

 

-

Fair value at December 31

 

11,134

 

12,782

 

19,486

 

21,461

 

386

 

427

 

(1)   Benefit payments for funded plans.  

92 


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 applicable tax rules 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.

 

 

 

2018

 

2017

 

2018

 

2017

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

Balance at December 31

 

 

 

 

 

 

 

 

 

Funded plans

 

(4,604)

 

(3,957)

 

439

 

413

 

Unfunded plans

 

(2,436)

 

(2,571)

 

(6,331)

 

(6,915)

Total

 

(7,040)

 

(6,528)

 

(5,892)

 

(6,502)

 

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

 

 

 

2018

 

2017

 

2018

 

2017

 

2018

 

2017

 

 

 

(millions of dollars)

Assets in excess of/(less than) benefit obligation

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31 (1) 

 

(7,040)

 

(6,528)

 

(5,892)

 

(6,502)

 

(7,085)

 

(7,673)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in the consolidated balance

 

 

 

 

 

 

 

 

 

 

 

 

 

sheet consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Other assets

 

-

 

-

 

1,174

 

1,403

 

-

 

-

 

Current liabilities

 

(243)

 

(276)

 

(314)

 

(338)

 

(362)

 

(360)

 

Postretirement benefits reserves

 

(6,797)

 

(6,252)

 

(6,752)

 

(7,567)

 

(6,723)

 

(7,313)

Total recorded

 

(7,040)

 

(6,528)

 

(5,892)

 

(6,502)

 

(7,085)

 

(7,673)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amounts recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income consist of:

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

3,831

 

3,982

 

4,713

 

5,586

 

877

 

1,595

 

Prior service cost

 

6

 

11

 

(93)

 

(143)

 

(357)

 

(397)

Total recorded in accumulated other

 

 

 

 

 

 

 

 

 

 

 

 

 

comprehensive income

 

3,837

 

3,993

 

4,620

 

5,443

 

520

 

1,198

 

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

93 


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

 

 

 

 

 

2018

 

2017

 

2016

 

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Weighted-average assumptions used to

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

determine net periodic benefit cost for

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

years ended December 31

(percent)

 

Discount rate

 

3.80

 

4.25

 

4.25

 

2.80

 

3.00

 

3.60

 

3.80

 

4.25

 

4.25

 

Long-term rate of return on funded assets

 

6.00

 

6.50

 

6.50

 

4.70

 

5.20

 

5.25

 

6.00

 

6.50

 

6.50

 

Long-term rate of compensation increase

 

5.75

 

5.75

 

5.75

 

4.30

 

4.00

 

4.80

 

5.75

 

5.75

 

5.75

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Components of net periodic benefit cost

 

(millions of dollars)

 

Service cost

 

819

 

784

 

810

 

608

 

596

 

585

 

152

 

129

 

153

 

Interest cost

 

721

 

798

 

793

 

754

 

772

 

844

 

301

 

317

 

344

 

Expected return on plan assets

 

(727)

 

(775)

 

(726)

 

(951)

 

(1,000)

 

(927)

 

(23)

 

(24)

 

(25)

 

Amortization of actuarial loss/(gain)

 

362

 

438

 

492

 

409

 

476

 

536

 

116

 

96

 

153

 

Amortization of prior service cost

 

5

 

5

 

6

 

46

 

47

 

54

 

(40)

 

(33)

 

(30)

 

Net pension enhancement and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    curtailment/settlement cost

 

268

 

609

 

319

 

44

 

19

 

2

 

-

 

-

 

-

Net periodic benefit cost

 

1,448

 

1,859

 

1,694

 

910

 

910

 

1,094

 

506

 

485

 

595

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in amounts recorded in accumulated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net actuarial loss/(gain)

 

479

 

(324)

 

27

 

(66)

 

(191)

 

(156)

 

(594)

 

215

 

(555)

 

Amortization of actuarial (loss)/gain

 

(630)

 

(1,047)

 

(811)

 

(453)

 

(495)

 

(538)

 

(116)

 

(96)

 

(153)

 

Prior service cost/(credit)

 

-

 

-

 

-

 

98

 

111

 

32

 

-

 

-

 

-

 

Amortization of prior service (cost)/credit

 

(5)

 

(5)

 

(6)

 

(46)

 

(47)

 

(54)

 

40

 

33

 

30

 

Foreign exchange rate changes

 

-

 

-

 

-

 

(356)

 

559

 

(108)

 

(8)

 

8

 

5

Total recorded in other comprehensive income

 

(156)

 

(1,376)

 

(790)

 

(823)

 

(63)

 

(824)

 

(678)

 

160

 

(673)

Total recorded in net periodic benefit cost and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    other comprehensive income, before tax

 

1,292

 

483

 

904

 

87

 

847

 

270

 

(172)

 

645

 

(78)

 

Costs for defined contribution plans were $391 million, $384 million and $399 million in 2018, 2017 and 2016, respectively.

94 


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

 

 

 

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

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

 

 

 

 

 

 

 

 

U.S. pension

 

 

156

 

1,376

 

790

 

Non-U.S. pension

 

 

823

 

63

 

824

 

Other postretirement benefits

 

 

678

 

(160)

 

673

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

 

 

1,657

 

1,279

 

2,287

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

 

 

(470)

 

(290)

 

(692)

(Charge)/credit to investment in equity companies

 

 

24

 

(43)

 

(16)

(Charge)/credit to other comprehensive income including noncontrolling

 

 

 

 

 

 

 

interests, after tax

 

 

1,211

 

946

 

1,579

Charge/(credit) to equity of noncontrolling interests

 

 

(114)

 

12

 

24

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

 

 

1,097

 

958

 

1,603

 

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive global equity and local currency 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 investment grade 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 30 percent equity securities and 70 percent debt securities. The equity targets for the U.S. and certain non-U.S. plans include a small 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.

95 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The 2018 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, 2018, Using:

 

 

at December 31, 2018, Using:

 

 

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

    Value (1) 

Total

 

Level 1

 

 

Level 2

 

 

Level 3

 

    Value (1) 

Total

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

-

 

 

-

 

-

 

1,397

 

1,397

 

-

 

 

-

 

-

 

2,648

 

2,648

 

 

Non-U.S.

-

 

 

-

 

-

 

1,218

 

1,218

 

57

 (2) 

-

 

-

 

2,436

 

2,493

 

Private equity

-

 

 

-

 

 

-

 

516

 

516

 

-

 

 

-

 

 

-

 

513

 

513

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

-

 

 

4,795

 (3) 

-

 

1

 

4,796

 

-

 

 

102

 (3) 

-

 

3,713

 

3,815

 

 

Government

-

 

 

3,085

 (3) 

-

 

2

 

3,087

 

243

 (4) 

97

 (3) 

-

 

9,326

 

9,666

 

 

Asset-backed

-

 

 

-

 

-

 

1

 

1

 

-

 

 

28

 (3) 

-

 

218

 

246

 

Cash

-

 

 

-

 

-

 

111

 

111

 

27

 

 

3

 (5) 

-

 

54

 

84

Total at fair value

-

 

 

7,880

 

 

-

 

3,246

 

11,126

 

327

 

 

230

 

 

-

 

18,908

 

19,465

 

Insurance contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

 

8

 

 

 

 

 

 

 

 

 

 

 

21

Total plan assets

 

 

 

 

 

 

 

 

 

 

11,134

 

 

 

 

 

 

 

 

 

 

 

19,486

 

(1)   Per ASU 2015-07, certain instruments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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

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

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

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

  

96 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Other Postretirement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2018, Using:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

       Value (1) 

 

Total

 

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

-

 

 

-

 

-

 

 

64

 

 

64

 

 

Non-U.S.

 

-

 

 

-

 

-

 

 

41

 

 

41

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

-

 

 

88

 (2) 

-

 

 

-

 

 

88

 

 

Government

 

-

 

 

189

 (2) 

-

 

 

-

 

 

189

 

 

Asset-backed

 

-

 

 

-

 

-

 

 

-

 

 

-

 

Cash

 

-

 

 

-

 

 

-

 

 

4

 

 

4

Total at fair value

 

-

 

 

277

 

 

-

 

 

109

 

 

386

 

(1)  Per ASU 2015-07, certain instruments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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

97 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The 2017 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, 2017, Using:

 

 

at December 31, 2017, Using:

 

 

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

    Value (1) 

Total

 

Level 1

 

 

Level 2

 

 

Level 3

 

    Value (1) 

Total

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

-

 

 

-

 

-

 

1,665

 

1,665

 

-

 

 

-

 

-

 

2,967

 

2,967

 

 

Non-U.S.

-

 

 

-

 

-

 

1,570

 

1,570

 

111

 (2) 

-

 

-

 

2,903

 

3,014

 

Private equity

-

 

 

-

 

 

-

 

532

 

532

 

-

 

 

-

 

 

-

 

522

 

522

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

-

 

 

5,260

 (3) 

-

 

1

 

5,261

 

-

 

131

 (3) 

-

 

5,215

 

5,346

 

 

Government

-

 

 

3,604

 (3) 

-

 

2

 

3,606

 

237

 (4) 

32

 (3) 

-

 

9,056

 

9,325

 

 

Asset-backed

-

 

 

-

 

-

 

1

 

1

 

-

 

 

34

 (3) 

-

 

72

 

106

 

Cash

-

 

 

-

 

-

 

138

 

138

 

54

 

 

2

 (5) 

-

 

102

 

158

Total at fair value

-

 

 

8,864

 

 

-

 

3,909

 

12,773

 

402

 

 

199

 

 

-

 

20,837

 

21,438

 

Insurance contracts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at contract value

 

 

 

 

 

 

 

 

 

 

9

 

 

 

 

 

 

 

 

 

 

 

23

Total plan assets

 

 

 

 

 

 

 

 

 

 

12,782

 

 

 

 

 

 

 

 

 

 

 

21,461

 

(1)   Per ASU 2015-07, certain instruments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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

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

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

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

 

 

   

98 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

Other Postretirement

 

 

 

Fair Value Measurement

 

 

 

 

 

at December 31, 2017, Using:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Asset

 

 

 

 

 

 

Level 1

 

Level 2

 

Level 3

 

       Value  (1) 

 

Total

 

 

 

(millions of dollars)

Asset category:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

-

 

 

-

 

-

 

 

73

 

 

73

 

 

Non-U.S.

 

-

 

 

-

 

-

 

 

55

 

 

55

 

Debt securities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Corporate

 

-

 

 

99

 (2) 

-

 

 

-

 

 

99

 

 

Government

 

-

 

 

197

 (2) 

-

 

 

-

 

 

197

 

 

Asset-backed

 

-

 

 

1

 (2) 

-

 

 

-

 

 

1

 

Cash

 

-

 

 

-

 

 

-

 

 

2

 

 

2

Total at fair value

 

-

 

 

297

 

 

-

 

 

130

 

 

427

 

(1)   Per ASU 2015-07, certain instruments that are measured at fair value using the Net Asset Value (NAV) per share practical expedient have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the total value of plan assets.

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

99 


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.

 

 

 

2018

 

2017

 

 

2018

 

2017

 

 

(millions of dollars)

For funded  pension plans with an accumulated benefit obligation

 

 

 

 

 

 

 

 

 

 

in excess of plan assets:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

15,738

 

16,739

 

 

4,037

 

3,384

 

Accumulated benefit obligation

 

13,208

 

14,022

 

 

3,671

 

3,264

 

Fair value of plan assets

 

11,134

 

12,782

 

 

3,499

 

3,219

 

 

 

 

 

 

 

 

 

 

 

For unfunded  pension plans:

 

 

 

 

 

 

 

 

 

 

Projected benefit obligation

 

2,436

 

2,571

 

 

6,331

 

6,915

 

Accumulated benefit obligation

 

1,475

 

1,535

 

 

5,670

 

6,208

 

 

 

 

 

 

 

Other

 

 

 

Pension Benefits

 

Postretirement

 

 

 

U.S.

 

Non-U.S.

 

Benefits

 

 

(millions of dollars)

Estimated 2019 amortization from accumulated other comprehensive income:

 

 

 

 

 

 

 

 

Net actuarial loss/(gain) (1) 

 

510

 

357

 

 

59

 

Prior service cost (2) 

 

5

 

48

 

 

(42)

 

(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 2019

 

1,020

 

680

 

-

 

 

-

 

Benefit payments expected in:

 

 

 

 

 

 

 

 

 

 

 

2019

 

1,353

 

1,113

 

454

 

 

19

 

 

2020

 

1,312

 

1,111

 

458

 

 

20

 

 

2021

 

1,310

 

1,127

 

461

 

 

20

 

 

2022

 

1,302

 

1,138

 

463

 

 

22

 

 

2023

 

1,307

 

1,156

 

456

 

 

23

 

 

2024 - 2028

 

6,393

 

5,806

 

2,259

 

 

126

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 recognized 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.

100 


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 $84 million in 2018, $136 million in 2017 and $63 million in 2016.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax (1) 

 

1,739

 

12,340

 

 

2,962

 

3,048

 

 

1,642

 

1,709

 

 

(2,600)

 

20,840

Earnings of equity companies included above

 

608

 

5,816

 

 

156

 

(6)

 

 

48

 

1,113

 

 

(380)

 

7,355

Sales and other operating revenue

 

10,359

 

15,158

 

 

74,327

 

147,007

 

 

12,239

 

20,204

 

 

38

 

279,332

Intersegment revenue

 

8,683

 

29,659

 

 

21,954

 

29,888

 

 

9,044

 

7,217

 

 

205

 

-

Depreciation and depletion expense

 

6,024

 

9,257

 

 

684

 

890

 

 

405

 

606

 

 

879

 

18,745

Interest revenue

 

-

 

-

 

 

-

 

-

 

 

-

 

-

 

 

64

 

64

Interest expense

 

77

 

31

 

 

2

 

12

 

 

-

 

1

 

 

643

 

766

Income tax expense (benefit)

 

104

 

8,149

 

 

946

 

1,008

 

 

566

 

245

 

 

(1,486)

 

9,532

Additions to property, plant and equipment

 

7,119

 

7,974

 

 

1,152

 

1,595

 

 

1,146

 

348

 

 

717

 

20,051

Investments in equity companies

 

4,566

 

16,337

 

 

293

 

1,162

 

 

870

 

3,431

 

 

(277)

 

26,382

Total assets

 

90,310

 

148,914

 

 

17,898

 

34,024

 

 

14,904

 

21,131

 

 

19,015

 

346,196

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

6,622

 

6,733

 

 

1,948

 

3,649

 

 

2,190

 

2,328

 

 

(3,760)

 

19,710

Earnings of equity companies included above

 

216

 

3,618

 

 

118

 

490

 

 

90

 

1,217

 

 

(369)

 

5,380

Sales and other operating revenue

 

9,349

 

14,508

 

 

61,695

 

122,881

 

 

11,035

 

17,659

 

 

35

 

237,162

Intersegment revenue

 

5,729

 

22,935

 

 

14,857

 

22,263

 

 

7,270

 

5,550

 

 

208

 

-

Depreciation and depletion expense

 

6,963

 

9,741

 

 

658

 

883

 

 

299

 

504

 

 

845

 

19,893

Interest revenue

 

-

 

-

 

 

-

 

-

 

 

-

 

-

 

 

36

 

36

Interest expense

 

87

 

29

 

 

1

 

6

 

 

-

 

-

 

 

478

 

601

Income tax expense (benefit)

 

(8,552)

 

5,463

 

 

(61)

 

934

 

 

362

 

664

 

 

16

 

(1,174)

Effect of U.S. tax reform - noncash

 

(7,602)

 

480

 

 

(618)

 

-

 

 

(335)

 

-

 

 

2,133

 

(5,942)

Additions to property, plant and equipment

 

9,761

 

8,617

 

 

769

 

1,551

 

 

1,330

 

2,019

 

 

854

 

24,901

Investments in equity companies

 

4,680

 

14,494

 

 

276

 

1,462

 

 

341

 

3,387

 

 

(286)

 

24,354

Total assets

 

89,048

 

155,822

 

 

18,172

 

34,294

 

 

13,363

 

21,133

 

 

16,859

 

348,691

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings after income tax

 

(4,151)

 

4,347

 

 

1,094

 

3,107

 

 

1,876

 

2,739

 

 

(1,172)

 

7,840

Earnings of equity companies included above

 

53

 

3,359

 

 

58

 

404

 

 

111

 

1,188

 

 

(367)

 

4,806

Sales and other operating revenue

 

7,552

 

12,278

 

 

52,630

 

102,756

 

 

9,944

 

15,447

 

 

21

 

200,628

Intersegment revenue

 

3,827

 

18,099

 

 

11,796

 

18,775

 

 

6,404

 

4,211

 

 

236

 

-

Depreciation and depletion expense

 

9,626

 

9,550

 

 

628

 

889

 

 

275

 

477

 

 

863

 

22,308

Interest revenue

 

-

 

-

 

 

-

 

-

 

 

-

 

-

 

 

30

 

30

Interest expense

 

17

 

29

 

 

1

 

8

 

 

-

 

-

 

 

398

 

453

Income tax expense (benefit)

 

(2,600)

 

1,818

 

 

396

 

951

 

 

693

 

609

 

 

(2,273)

 

(406)

Additions to property, plant and equipment

 

3,144

 

7,878

 

 

791

 

1,525

 

 

1,463

 

482

 

 

817

 

16,100

Investments in equity companies

 

4,917

 

11,364

 

 

111

 

1,255

 

 

158

 

3,247

 

 

(242)

 

20,810

Total assets

 

86,146

 

153,183

 

 

16,201

 

29,208

 

 

11,600

 

18,453

 

 

15,523

 

330,314

 

(1)  See Note 2 for additional details regarding the change in segmentation of Non-service pension and postretirement benefit expense.

  

101 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Geographic

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales and other operating revenue

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

96,930

 

82,079

 

70,126

Non-U.S.

 

182,402

 

155,083

 

130,502

 

Total

 

279,332

 

237,162

 

200,628

 

 

 

 

 

 

 

 

Significant non-U.S. revenue sources include:  (1) 

 

 

 

 

 

 

 

Canada

 

22,672

 

20,116

 

17,682

 

United Kingdom

 

18,702

 

16,611

 

15,452

 

Belgium

 

15,664

 

13,633

 

10,834

 

Singapore

 

13,689

 

11,589

 

9,919

 

France

 

13,637

 

11,235

 

9,487

 

Italy

 

13,396

 

11,476

 

9,715

 

Germany

 

9,426

 

8,484

 

7,899

 

(1)  Revenue is determined by primary country of operations. Excludes certain sales and other operating revenues in Non-U.S. operations where attribution to a specific country is not practicable.

 

Long-lived assets

 

2018

 

2017

 

2016

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

United States

 

108,147

 

105,101

 

101,194

Non-U.S.

 

138,954

 

147,529

 

143,030

 

Total

 

247,101

 

252,630

 

244,224

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

Canada

 

37,433

 

41,138

 

40,144

 

Australia

 

14,548

 

16,908

 

16,510

 

Singapore

 

11,148

 

11,292

 

9,769

 

Kazakhstan

 

9,726

 

10,121

 

10,325

 

Nigeria

 

8,421

 

9,734

 

11,314

 

Papua New Guinea

 

8,269

 

8,463

 

5,719

 

Angola

 

7,021

 

7,689

 

8,413

 

Russia

 

5,456

 

5,702

 

4,828

102 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

19. Income and Other Taxes

 

 

 

 

 

 

 

 

2018

 

 

 

 

 

2017

 

 

 

 

 

2016

 

 

 

 

 

 

 

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

 

459

 

9,001

 

9,460

 

577

 

6,633

 

7,210

 

(214)

 

4,056

 

3,842

 

 

Deferred - net

 

518

 

(614)

 

(96)

 

(9,075)

 

754

 

(8,321)

 

(2,801)

 

(1,422)

 

(4,223)

 

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

 

42

 

-

 

42

 

17

 

-

 

17

 

41

 

-

 

41

 

 

 

Total federal and non-U.S.

 

1,019

 

8,387

 

9,406

 

(8,481)

 

7,387

 

(1,094)

 

(2,974)

 

2,634

 

(340)

 

State

 

126

 

-

 

126

 

(80)

 

-

 

(80)

 

(66)

 

-

 

(66)

 

 

 

Total income tax expense

 

1,145

 

8,387

 

9,532

 

(8,561)

 

7,387

 

(1,174)

 

(3,040)

 

2,634

 

(406)

All other taxes and duties

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other taxes and duties

 

3,498

 

29,165

 

32,663

 

3,330

 

26,774

 

30,104

 

3,209

 

25,811

 

29,020

 

Included in production and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

manufacturing expenses

 

1,245

 

857

 

2,102

 

1,107

 

747

 

1,854

 

1,052

 

808

 

1,860

 

Included in SG&A expenses

 

153

 

312

 

465

 

147

 

354

 

501

 

133

 

362

 

495

 

 

Total other taxes and duties

 

4,896

 

30,334

 

35,230

 

4,584

 

27,875

 

32,459

 

4,394

 

26,981

 

31,375

 

 

 

Total

 

6,041

 

38,721

 

44,762

 

(3,977)

 

35,262

 

31,285

 

1,354

 

29,615

 

30,969

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The above provisions for deferred income taxes include a net credit of $289 million in 2018 related to changes in tax laws and rates, mainly from a $291 million credit related to U.S. tax reform. For 2017, deferred income tax expense includes a net credit of $5,920 million, reflecting a $5,942 million credit related to U.S. tax reform and $22 million of other changes in tax laws and rates outside of the United States. Deferred income tax expense for 2016 includes net charges of $180 million for the effect of changes in tax laws and rates.

Following the December 22, 2017, enactment of the U.S. Tax Cuts and Jobs Act, in accordance with Accounting Standard Codification Topic 740 (Income Taxes) and following the guidance outlined in the SEC Staff Accounting Bulletin No. 118, the Corporation included a $5,942 million credit in its 2017 results, representing a reasonable estimate of the income tax effects of the changes in tax law and tax rate. The Corporation’s results for 2018 include a $291 million tax credit, mainly in the Non-U.S. Upstream, reflecting an updated estimate of the impact of U.S. tax reform including clarifications provided in proposed transition tax regulations issued by the U.S. Treasury in 2018. The Corporation has completed its accounting for the enactment-date income tax effects of the U.S. Tax Cuts and Jobs Act in accordance with Accounting Standard Codification Topic 740 (Income Taxes).

103 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 21 percent for 2018 and 35 percent for 2017 and 2016 is as follows:

  

 

 

 

 

2018

 

2017

 

2016

 

 

 

 

(millions of dollars)

Income before income taxes

 

 

 

 

 

 

 

United States

 

5,200

 

(754)

 

(5,832)

 

Non-U.S.

 

25,753

 

19,428

 

13,801

 

 

Total

 

30,953

 

18,674

 

7,969

Theoretical tax

 

6,500

 

6,536

 

2,789

Effect of equity method of accounting

 

(1,545)

 

(1,883)

 

(1,682)

Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1) 

 

4,626

 

1,848

 

(582)

Enactment-date effects of U.S. tax reform

 

(291)

 

(5,942)

 

-

Other (2) 

 

242

 

(1,733)

 

(931)

 

 

Total income tax expense

 

9,532

 

(1,174)

 

(406)

 

 

 

 

 

 

 

 

 

Effective tax rate calculation

 

 

 

 

 

 

Income taxes

 

9,532

 

(1,174)

 

(406)

ExxonMobil share of equity company income taxes

 

3,142

 

2,228

 

1,692

 

 

Total income taxes

 

12,674

 

1,054

 

1,286

Net income including noncontrolling interests

 

21,421

 

19,848

 

8,375

 

 

Total income before taxes

 

34,095

 

20,902

 

9,661

 

 

 

 

 

 

 

 

 

Effective income tax rate

 

37%

 

5%

 

13%

 

(1)  2016 includes a $227 million expense from an adjustment to deferred taxes and a $548 million benefit from an adjustment to a tax position in prior years.

(2)  2017 includes an exploration tax benefit of $708 million. 2016 includes an exploration tax benefit of $198 million and benefits from an adjustment to a prior year tax position of $176 million.  

  

104 


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:

 

2018

 

2017

 

 

 

(millions of dollars)

 

 

 

 

 

 

Property, plant and equipment

 

35,745

 

36,559

Other liabilities

 

6,516

 

5,625

 

Total deferred tax liabilities

 

42,261

 

42,184

 

 

 

 

 

 

Pension and other postretirement benefits

 

(4,115)

 

(4,338)

Asset retirement obligations

 

(4,118)

 

(4,237)

Tax loss carryforwards

 

(6,321)

 

(6,767)

Other assets

 

(5,498)

 

(5,832)

 

Total deferred tax assets

 

(20,052)

 

(21,174)

 

 

 

 

 

 

Asset valuation allowances

 

1,826

 

2,565

 

Net deferred tax liabilities

 

24,035

 

23,575

 

In 2018, asset valuation allowances of $1,826 million decreased by $739 million, including $234 million related to U.S. tax reform and $333 million related to a reduction in deferred tax assets.

 

Balance sheet classification

 

2018

 

2017

 

 

 

(millions of dollars)

 

 

 

 

 

 

Other assets, including intangibles, net

 

(3,209)

 

(3,318)

Deferred income tax liabilities

 

27,244

 

26,893

 

Net deferred tax liabilities

 

24,035

 

23,575

 

The Corporation’s undistributed earnings from subsidiary companies outside the United States include amounts that have been retained to fund prior and future capital project expenditures. Deferred income taxes have not been recorded for potential future tax obligations, such as foreign withholding tax and state tax, as these undistributed earnings are expected to be indefinitely reinvested for the foreseeable future. As of December 31, 2018, it is not practicable to estimate the unrecognized deferred tax liability. However, unrecognized deferred taxes on remittance of these funds are not expected to be material.

  

105 


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

2018

 

2017

 

2016

 

 

(millions of dollars)

 

 

 

 

 

 

 

Balance at January 1

8,783

 

9,468

 

9,396

 

Additions based on current year's tax positions

375

 

522

 

655

 

Additions for prior years' tax positions

240

 

523

 

534

 

Reductions for prior years' tax positions

(125)

 

(865)

 

(1,019)

 

Reductions due to lapse of the statute of limitations

(5)

 

(113)

 

(7)

 

Settlements with tax authorities

(68)

 

(782)

 

(70)

 

Foreign exchange effects/other

(26)

 

30

 

(21)

Balance at December 31

9,174

 

8,783

 

9,468

 

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 2018, 2017 and 2016 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 ongoing U.S. federal income tax positions at issue with the Internal Revenue Service (IRS) for tax years beginning in 2006. The IRS has asserted penalties associated with several of those positions. The Corporation has not recognized the penalties as an expense because the Corporation does not expect the penalties to be sustained under applicable law. The Corporation has filed a refund suit for tax years 2006-2009 in a U.S. federal district court with respect to the positions at issue for those years. Unfavorable resolution of all positions at issue with the IRS would not have a materially adverse effect on the Corporation’s net income or liquidity.

It is reasonably possible that the total amount of unrecognized tax benefits could increase or decrease by 10 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

2018….. 

 

 

Angola

2017 - 2018

 

 

Australia

2008 - 2018

 

 

Belgium

2016 - 2018

 

 

Canada

2000 - 2018

 

 

Equatorial Guinea

2007 - 2018

 

 

Indonesia

2007 - 2018

 

 

Iraq

2013 - 2018

 

 

Malaysia

2009 - 2018

 

 

Nigeria

2006 - 2018

 

 

Norway

2007 - 2018

 

 

Papua New Guinea

2008 - 2018

 

 

Russia

2016 - 2018

 

 

United Kingdom

2015 - 2018

 

 

United States

2006 - 2018

 

 

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 $3 million, $36 million and $4 million in interest expense on income tax reserves in 2018, 2017 and 2016, respectively. The related interest payable balances were $169 million and $168 million at December 31, 2018, and 2017, respectively.

  

 

106 


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 $1,484 million in 2018, $1,402 million in 2017 and $719 million in 2016. 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

 

Other

 

 

 

 

 

 

 

Australia/

 

 

Results of Operations

 

States

 

Americas

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

5,914

 

1,491

 

3,680

 

1,136

 

2,431

 

3,256

 

17,908

 

 

Transfers

 

5,822

 

4,633

 

1,573

 

8,844

 

8,461

 

873

 

30,206

 

 

 

 

11,736

 

6,124

 

5,253

 

9,980

 

10,892

 

4,129

 

48,114

 

Production costs excluding taxes

 

3,915

 

4,211

 

1,348

 

2,454

 

1,501

 

680

 

14,109

 

Exploration expenses

 

237

 

434

 

140

 

318

 

209

 

128

 

1,466

 

Depreciation and depletion

 

5,775

 

1,803

 

665

 

2,788

 

2,088

 

809

 

13,928

 

Taxes other than income

 

953

 

133

 

128

 

799

 

1,155

 

335

 

3,503

 

Related income tax

 

250

 

(121)

 

1,934

 

1,766

 

4,008

 

622

 

8,459

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

606

 

(336)

 

1,038

 

1,855

 

1,931

 

1,555

 

6,649

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

747

 

-

 

1,420

 

-

 

12,028

 

-

 

14,195

 

 

Transfers

 

588

 

-

 

8

 

-

 

935

 

-

 

1,531

 

 

 

 

1,335

 

-

 

1,428

 

-

 

12,963

 

-

 

15,726

 

Production costs excluding taxes

 

535

 

-

 

745

 

5

 

409

 

-

 

1,694

 

Exploration expenses

 

1

 

-

 

4

 

-

 

5

 

-

 

10

 

Depreciation and depletion

 

248

 

-

 

172

 

-

 

462

 

-

 

882

 

Taxes other than income

 

33

 

-

 

61

 

-

 

4,104

 

-

 

4,198

 

Related income tax

 

-

 

-

 

271

 

(1)

 

2,726

 

-

 

2,996

 

Results of producing activities for equity companies

 

518

 

-

 

175

 

(4)

 

5,257

 

-

 

5,946

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

1,124

 

(336)

 

1,213

 

1,851

 

7,188

 

1,555

 

12,595

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

107 


   

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

 

 

 

 

United

 

Other

 

 

 

 

 

 

Australia/

 

Results of Operations

 

States

 

Americas

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

5,223

 

1,911

 

3,652

 

993

 

2,239

 

2,244

 

16,262

 

 

Transfers

 

3,852

 

3,462

 

1,631

 

7,771

 

6,035

 

689

 

23,440

 

 

 

 

9,075

 

5,373

 

5,283

 

8,764

 

8,274

 

2,933

 

39,702

 

Production costs excluding taxes

 

3,730

 

3,833

 

1,576

 

2,064

 

1,618

 

626

 

13,447

 

Exploration expenses

 

162

 

647

 

94

 

311

 

494

 

82

 

1,790

 

Depreciation and depletion

 

6,689

 

2,005

 

1,055

 

2,957

 

1,782

 

913

 

15,401

 

Taxes other than income

 

684

 

97

 

146

 

559

 

811

 

311

 

2,608

 

Related income tax

 

(8,066)

 

(180)

 

1,717

 

1,911

 

2,148

 

316

 

(2,154)

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

5,876

 

(1,029)

 

695

 

962

 

1,421

 

685

 

8,610

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

585

 

-

 

1,636

 

-

 

8,926

 

-

 

11,147

 

 

Transfers

 

443

 

-

 

10

 

-

 

638

 

-

 

1,091

 

 

 

 

1,028

 

-

 

1,646

 

-

 

9,564

 

-

 

12,238

 

Production costs excluding taxes

 

523

 

-

 

418

 

-

 

336

 

-

 

1,277

 

Exploration expenses

 

1

 

-

 

13

 

-

 

878

 

-

 

892

 

Depreciation and depletion

 

320

 

-

 

166

 

-

 

477

 

-

 

963

 

Taxes other than income

 

33

 

-

 

679

 

-

 

2,997

 

-

 

3,709

 

Related income tax

 

-

 

-

 

130

 

-

 

1,924

 

-

 

2,054

 

Results of producing activities for equity companies

 

151

 

-

 

240

 

-

 

2,952

 

-

 

3,343

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

6,027

 

(1,029)

 

935

 

962

 

4,373

 

685

 

11,953

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

4,424

 

1,511

 

2,921

 

705

 

1,826

 

1,273

 

12,660

 

 

Transfers

 

2,323

 

2,652

 

1,568

 

6,498

 

4,638

 

578

 

18,257

 

 

 

 

6,747

 

4,163

 

4,489

 

7,203

 

6,464

 

1,851

 

30,917

 

Production costs excluding taxes

 

3,590

 

3,651

 

1,794

 

2,216

 

1,331

 

531

 

13,113

 

Exploration expenses

 

220

 

572

 

94

 

292

 

205

 

84

 

1,467

 

Depreciation and depletion

 

9,334

 

1,601

 

1,678

 

3,573

 

1,613

 

532

 

18,331

 

Taxes other than income

 

491

 

165

 

139

 

762

 

621

 

209

 

2,387

 

Related income tax

 

(2,543)

 

(688)

 

546

 

(149)

 

1,767

 

167

 

(900)

 

Results of producing activities for consolidated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

subsidiaries

 

(4,345)

 

(1,138)

 

238

 

509

 

927

 

328

 

(3,481)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016 - Revenue

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to third parties

 

506

 

-

 

1,677

 

-

 

7,208

 

-

 

9,391

 

 

Transfers

 

344

 

-

 

9

 

-

 

418

 

-

 

771

 

 

 

 

850

 

-

 

1,686

 

-

 

7,626

 

-

 

10,162

 

Production costs excluding taxes

 

527

 

-

 

529

 

-

 

504

 

-

 

1,560

 

Exploration expenses

 

-

 

-

 

36

 

-

 

21

 

-

 

57

 

Depreciation and depletion

 

301

 

-

 

143

 

-

 

437

 

-

 

881

 

Taxes other than income

 

31

 

-

 

661

 

-

 

2,456

 

-

 

3,148

 

Related income tax

 

-

 

-

 

86

 

-

 

1,472

 

-

 

1,558

 

Results of producing activities for equity companies

 

(9)

 

-

 

231

 

-

 

2,736

 

-

 

2,958

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total results of operations

 

(4,354)

 

(1,138)

 

469

 

509

 

3,663

 

328

 

(523)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

108 


   

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $13,474 million less at year-end 2018 and $15,292 million less at year-end 2017 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

 

Other

 

 

 

 

 

 

Australia/

 

Capitalized Costs

 

 

States

 

Americas

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

17,996

 

2,482

 

147

 

982

 

2,944

 

722

 

25,273

 

 

- Unproved

 

26,357

 

6,872

 

45

 

155

 

179

 

2,692

 

36,300

 

 

Total property costs

 

 

44,353

 

9,354

 

192

 

1,137

 

3,123

 

3,414

 

61,573

 

Producing assets

 

 

95,532

 

45,874

 

28,564

 

53,722

 

39,173

 

13,587

 

276,452

 

Incomplete construction

 

 

4,174

 

2,873

 

1,475

 

3,368

 

4,985

 

1,525

 

18,400

 

 

Total capitalized costs

 

 

144,059

 

58,101

 

30,231

 

58,227

 

47,281

 

18,526

 

356,425

 

Accumulated depreciation and depletion

 

62,950

 

18,994

 

25,803

 

40,710

 

20,206

 

6,574

 

175,237

 

Net capitalized costs for consolidated subsidiaries

 

81,109

 

39,107

 

4,428

 

17,517

 

27,075

 

11,952

 

181,188

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

98

 

-

 

4

 

309

 

-

 

-

 

411

 

 

- Unproved

 

10

 

-

 

-

 

3,111

 

-

 

-

 

3,121

 

 

Total property costs

 

 

108

 

-

 

4

 

3,420

 

-

 

-

 

3,532

 

Producing assets

 

 

6,766

 

-

 

5,547

 

-

 

7,719

 

-

 

20,032

 

Incomplete construction

 

 

148

 

-

 

12

 

581

 

7,044

 

-

 

7,785

 

 

Total capitalized costs

 

 

7,022

 

-

 

5,563

 

4,001

 

14,763

 

-

 

31,349

 

Accumulated depreciation and depletion

 

2,968

 

-

 

4,653

 

-

 

4,843

 

-

 

12,464

 

Net capitalized costs for equity companies

 

4,054

 

-

 

910

 

4,001

 

9,920

 

-

 

18,885

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

17,380

 

2,560

 

139

 

982

 

2,624

 

778

 

24,463

 

 

- Unproved

 

27,051

 

5,238

 

62

 

196

 

179

 

2,701

 

35,427

 

 

Total property costs

 

 

44,431

 

7,798

 

201

 

1,178

 

2,803

 

3,479

 

59,890

 

Producing assets

 

 

94,253

 

48,951

 

30,908

 

52,137

 

37,808

 

14,564

 

278,621

 

Incomplete construction

 

 

2,016

 

1,484

 

1,173

 

4,294

 

5,499

 

1,440

 

15,906

 

 

Total capitalized costs

 

 

140,700

 

58,233

 

32,282

 

57,609

 

46,110

 

19,483

 

354,417

 

Accumulated depreciation and depletion

 

61,041

 

18,780

 

27,040

 

37,924

 

18,354

 

6,279

 

169,418

 

Net capitalized costs for consolidated subsidiaries

 

79,659

 

39,453

 

5,242

 

19,685

 

27,756

 

13,204

 

184,999

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property (acreage) costs

- Proved

 

78

 

-

 

4

 

309

 

-

 

-

 

391

 

 

- Unproved

 

11

 

-

 

-

 

3,111

 

59

 

-

 

3,181

 

 

Total property costs

 

 

89

 

-

 

4

 

3,420

 

59

 

-

 

3,572

 

Producing assets

 

 

6,410

 

-

 

5,678

 

-

 

9,824

 

-

 

21,912

 

Incomplete construction

 

 

98

 

-

 

45

 

516

 

4,611

 

-

 

5,270

 

 

Total capitalized costs

 

 

6,597

 

-

 

5,727

 

3,936

 

14,494

 

-

 

30,754

 

Accumulated depreciation and depletion

 

2,722

 

-

 

4,625

 

-

 

6,519

 

-

 

13,866

 

Net capitalized costs for equity companies

 

3,875

 

-

 

1,102

 

3,936

 

7,975

 

-

 

16,888

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

109 


   

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 2018 were $16,328 million, down $3,316 million from 2017, due primarily to lower acquisition costs of unproved properties, partially offset by higher development costs. In 2017 costs were $19,644 million, up $8,269 million from 2016, due primarily to acquisitions of unproved properties, partially offset by lower development costs including lower asset retirement obligation cost estimates mainly in the North Sea. Total equity company costs incurred in 2018 were $3,031 million, down $2,977 million from 2017, due primarily to lower acquisition costs of unproved properties.



 

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

Costs Incurred in Property Acquisitions,

 

United

 

Other

 

 

 

 

 

 

Australia/

 

Exploration and Development Activities

 

States

 

Americas

 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

(millions of dollars)

During 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

7

 

3

 

-

 

-

 

321

 

-

 

331

 

 

 

- Unproved

 

238

 

2,109

 

-

 

1

 

-

 

-

 

2,348

 

 

Exploration costs

 

 

235

 

1,113

 

147

 

342

 

217

 

174

 

2,228

 

 

Development costs

 

 

7,440

 

1,734

 

96

 

791

 

1,104

 

256

 

11,421

 

 

Total costs incurred for consolidated subsidiaries

 

7,920

 

4,959

 

243

 

1,134

 

1,642

 

430

 

16,328

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

21

 

-

 

-

 

-

 

-

 

-

 

21

 

 

 

- Unproved

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

 

Exploration costs

 

 

1

 

-

 

4

 

-

 

5

 

-

 

10

 

 

Development costs

 

 

442

 

-

 

40

 

66

 

2,452

 

-

 

3,000

 

 

Total costs incurred for equity companies

 

464

 

-

 

44

 

66

 

2,457

 

-

 

3,031

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

88

 

5

 

-

 

50

 

583

 

-

 

726

 

 

 

- Unproved

 

6,167

 

1,004

 

35

 

70

 

-

 

2,601

 

9,877

 

 

Exploration costs

 

 

190

 

702

 

109

 

373

 

224

 

509

 

2,107

 

 

Development costs

 

 

3,752

 

877

 

(39)

 

628

 

1,450

 

266

 

6,934

 

 

Total costs incurred for consolidated subsidiaries

 

10,197

 

2,588

 

105

 

1,121

 

2,257

 

3,376

 

19,644

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

-

 

-

 

-

 

309

 

-

 

-

 

309

 

 

 

- Unproved

 

-

 

-

 

-

 

3,111

 

-

 

-

 

3,111

 

 

Exploration costs

 

 

1

 

-

 

3

 

323

 

90

 

-

 

417

 

 

Development costs

 

 

137

 

-

 

41

 

192

 

1,801

 

-

 

2,171

 

 

Total costs incurred for equity companies

 

138

 

-

 

44

 

3,935

 

1,891

 

-

 

6,008

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

During 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

1

 

1

 

-

 

-

 

71

 

-

 

73

 

 

 

- Unproved

 

170

 

27

 

-

 

-

 

-

 

-

 

197

 

 

Exploration costs

 

 

145

 

689

 

156

 

321

 

187

 

133

 

1,631

 

 

Development costs

 

 

3,054

 

1,396

 

538

 

1,866

 

2,214

 

406

 

9,474

 

 

Total costs incurred for consolidated subsidiaries

 

3,370

 

2,113

 

694

 

2,187

 

2,472

 

539

 

11,375

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Property acquisition costs

- Proved

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

 

 

- Unproved

 

-

 

-

 

-

 

-

 

-

 

-

 

-

 

 

Exploration costs

 

 

1

 

-

 

36

 

-

 

32

 

-

 

69

 

 

Development costs

 

 

106

 

-

 

88

 

-

 

1,143

 

-

 

1,337

 

 

Total costs incurred for equity companies

 

107

 

-

 

124

 

-

 

1,175

 

-

 

1,406

110 


   

Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2016, 2017 and 2018.

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

Proved oil and natural gas reserves are those quantities of oil and natural 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 Corporation’s year-end reserves volumes as well as the reserves change categories shown in the following tables are required to be calculated on the basis of 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 flows.

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 the average of first-of-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment/facility capacity. Reserve volumes that were subject to a downward revision can be revised upward at some point in the future when price levels increase, costs decline, and / or operating efficiencies occur.

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. Natural gas reserves exclude the gaseous equivalent of liquids expected to be removed from the natural 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 reported for these types of arrangements typically vary inversely with oil and natural gas price changes. As oil and natural 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 2018 that were associated with production sharing contract arrangements was 8 percent of liquids, 10 percent of natural gas and 9 percent on an oil-equivalent basis (natural gas is converted to an oil-equivalent basis at six billion cubic feet per one 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, natural gas liquids, and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and natural gas reserves. The natural gas quantities differ from the quantities of natural gas delivered for sale by the producing function as reported in the Operating Information due to volumes consumed or flared and inventory changes.

The changes between 2018 year-end proved reserves and 2017 year-end proved reserves include upward revisions of 3.4 billion barrels of bitumen at Kearl as a result of improved prices; downward natural gas revisions for the Groningen field in the Netherlands; and extensions/discoveries primarily in the United States. In 2018, the Dutch Cabinet notified Parliament of its intention to further reduce previously legislated Groningen gas extraction in response to seismic events over the last several years. In anticipation of a lower production outlook, the Corporation reduced its estimate of proved reserves by 0.8 billion oil-equivalent barrels for the Groningen gas field.

The changes between 2017 year-end proved reserves and 2016 year-end proved reserves primarily reflect extensions/discoveries in the United States, Guyana, and the United Arab Emirates, as well as purchases in the Permian Basin and offshore Area 4 in Mozambique, along with upward revisions to North America natural gas, liquids in the United Arab Emirates, and bitumen at Kearl and Cold Lake. Downward revisions are reflected in Europe for the Groningen gas field.

The downward revisions in 2016, as the result of very low prices during 2016, included the entire 3.5 billion barrels of bitumen at Kearl. In addition, 0.8 billion barrels of oil equivalent across the remainder of North America no longer qualified as proved reserves at year-end 2016 mainly due to the acceleration of the projected end-of-field-life.

111 


   

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

Crude Oil

 

Liquids

 

Bitumen

 

Synthetic Oil

 

 

 

 

Canada/

 

 

 

 

 

 

Canada/

 

 

Canada/

 

 

 

 

United

Other

 

 

Australia/

 

 

 

Other

 

 

Other

 

 

 

 

States

Americas

Europe

Africa

Asia

Oceania

Total

Worldwide

Americas

 

 

Americas

 

Total

 

 

(millions of barrels)

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2016

2,378

260

184

963

2,825

125

6,735

 

1,078

 

4,560

 

 

581

 

12,954

 

Revisions

(307)

3

43

49

73

9

(130)

 

47

 

(3,748)

 

 

8

 

(3,823)

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

79

-

-

-

-

-

79

 

32

 

-

 

 

-

 

111

 

Sales

(15)

(5)

(3)

-

-

-

(23)

 

(5)

 

-

 

 

-

 

(28)

 

Extensions/discoveries

173

3

12

-

-

-

188

 

66

 

-

 

 

-

 

254

 

Production

(127)

(20)

(63)

(168)

(140)

(13)

(531)

 

(64)

 

(111)

 

 

(25)

 

(731)

December 31, 2016

2,181

241

173

844

2,758

121

6,318

 

1,154

 

701

 

 

564

 

8,737

Attributable to noncontrolling interests

8

 

 

 

 

 

 

2

 

213

 

 

171

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2016

254

-

25

-

1,077

-

1,356

 

414

 

-

 

 

-

 

1,770

 

Revisions

3

-

(7)

-

191

-

187

 

(5)

 

-

 

 

-

 

182

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Production

(21)

-

(1)

-

(85)

-

(107)

 

(25)

 

-

 

 

-

 

(132)

December 31, 2016

236

-

17

-

1,183

-

1,436

 

384

 

-

 

 

-

 

1,820

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2016

2,417

241

190

844

3,941

121

7,754

 

1,538

 

701

 

 

564

 

10,557

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2017

2,181

241

173

844

2,758

121

6,318

 

1,154

 

701

 

 

564

 

8,737

 

Revisions

70

19

43

30

490

2

654

 

(49)

 

416

 

 

(70)

 

951

 

Improved recovery

-

-

-

2

-

-

2

 

-

 

6

 

 

-

 

8

 

Purchases

428

5

-

-

-

-

433

 

164

 

-

 

 

-

 

597

 

Sales

(10)

-

(43)

-

-

-

(53)

 

(2)

 

-

 

 

-

 

(55)

 

Extensions/discoveries

158

161

-

3

384

-

706

 

58

 

-

 

 

-

 

764

 

Production

(132)

(16)

(54)

(150)

(136)

(13)

(501)

 

(67)

 

(111)

 

 

(21)

 

(700)

December 31, 2017

2,695

410

119

729

3,496

110

7,559

 

1,258

 

1,012

 

 

473

 

10,302

Attributable to noncontrolling interests

10

 

 

 

 

 

 

3

 

288

 

 

144

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2017

236

-

17

-

1,183

-

1,436

 

384

 

-

 

 

-

 

1,820

 

Revisions

29

-

(1)

-

-

-

28

 

4

 

-

 

 

-

 

32

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

-

-

-

6

-

-

6

 

-

 

-

 

 

-

 

6

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Production

(20)

-

(1)

-

(86)

-

(107)

 

(24)

 

-

 

 

-

 

(131)

December 31, 2017

245

-

15

6

1,097

-

1,363

 

364

 

-

 

 

-

 

1,727

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2017

2,940

410

134

735

4,593

110

8,922

 

1,622

 

1,012

 

 

473

 

12,029

112 


   

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

Crude Oil

 

Liquids

 

Bitumen

 

Synthetic Oil

 

 

 

 

Canada/

 

 

 

 

 

 

Canada/

 

 

Canada/

 

 

 

 

United

Other

 

 

Australia/

 

 

 

Other

 

 

Other

 

 

 

 

States

Americas

Europe

Africa

Asia

Oceania

Total

Worldwide

Americas

 

 

Americas

 

Total

 

 

(millions of barrels)

Net proved developed and

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

undeveloped reserves of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2018

2,695

410

119

729

3,496

110

7,559

 

1,258

 

1,012

 

 

473

 

10,302

 

Revisions

61

28

63

(9)

4

6

153

 

(16)

 

3,286

 

 

15

 

3,438

 

Improved recovery

-

-

23

13

-

-

36

 

-

 

-

 

 

-

 

36

 

Purchases

8

-

-

-

-

-

8

 

2

 

-

 

 

-

 

10

 

Sales

(11)

-

(2)

-

-

-

(13)

 

(13)

 

-

 

 

-

 

(26)

 

Extensions/discoveries

595

113

-

9

3

-

720

 

238

 

-

 

 

-

 

958

 

Production

(144)

(22)

(37)

(138)

(146)

(11)

(498)

 

(65)

 

(113)

 

 

(22)

 

(698)

December 31, 2018

3,204

529

166

604

3,357

105

7,965

 

1,404

 

4,185

 

 

466

 

14,020

Attributable to noncontrolling interests

44

 

 

 

 

 

 

4

 

962

 

 

142

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

reserves of equity companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2018

245

-

15

6

1,097

-

1,363

 

364

 

-

 

 

-

 

1,727

 

Revisions

28

-

1

-

6

-

35

 

1

 

-

 

 

-

 

36

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Purchases

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Sales

-

-

-

-

-

-

-

 

-

 

-

 

 

-

 

-

 

Extensions/discoveries

1

-

-

-

-

-

1

 

-

 

-

 

 

-

 

1

 

Production

(20)

-

(1)

-

(83)

-

(104)

 

(23)

 

-

 

 

-

 

(127)

December 31, 2018

254

-

15

6

1,020

-

1,295

 

342

 

-

 

 

-

 

1,637

Total liquids proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

at December 31, 2018

3,458

529

181

610

4,377

105

9,260

 

1,746

 

4,185

 

 

466

 

15,657

113 


   

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

Other

 

 

 

 

Australia/

 

 

Other

 

Other

 

 

 

 

 

States

Americas

 

Europe

Africa

Asia

Oceania

Total

 

Americas

 

Americas

 

Total

 

 

 

(millions of barrels)

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,317

87

 

175

836

1,858

105

4,378

 

436

 

564

 

5,378

 

 

Equity companies

210

-

 

11

-

1,114

-

1,335

 

-

 

-

 

1,335

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,626

169

 

31

169

1,025

74

3,094

 

265

 

-

 

3,359

 

 

Equity companies

36

-

 

6

-

443

-

485

 

-

 

-

 

485

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

3,189

256

 

223

1,005

4,440

179

9,292

 

701

 

564

 

10,557

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,489

92

 

119

676

2,182

131

4,689

 

657

 

473

 

5,819

 

 

Equity companies

208

-

 

14

-

1,019

-

1,241

 

-

 

-

 

1,241

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

2,167

337

 

30

137

1,426

31

4,128

 

355

 

-

 

4,483

 

 

Equity companies

48

-

 

1

6

431

-

486

 

-

 

-

 

486

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

3,912

429

 

164

819

5,058

162

10,544

 

1,012

 

473

 

12,029

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

1,696

153

 

123

578

2,285

118

4,953

 

3,880

 

466

 

9,299

 

 

Equity companies

208

-

 

15

-

919

-

1,142

 

-

 

-

 

1,142

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

2,616

403

 

78

111

1,173

35

4,416

 

305

 

-

 

4,721

 

 

Equity companies

56

-

 

-

6

433

-

495

 

-

 

-

 

495

Total liquids proved reserves at

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

4,576

556

 

216

695

4,810

153

11,006

(1)

4,185

 

466

 

15,657

 

(1)   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 2018 Form 10-K.

114 


   

Natural Gas and Oil-Equivalent Proved Reserves

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

Other

 

 

 

Australia/

 

 

Total

 

 

States

Americas

Europe

Africa

Asia

Oceania

Total

 

All Products (1) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2016

19,380

1,127

1,956

793

5,329

7,041

35,626

 

18,892

 

 

Revisions

(1,630)

(102)

126

21

(16)

658

(943)

 

(3,980)

 

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

 

Purchases

148

-

-

-

-

-

148

 

135

 

 

Sales

(45)

(12)

(2)

-

-

-

(59)

 

(38)

 

 

Extensions/discoveries

1,156

34

6

-

-

-

1,196

 

453

 

 

Production

(1,223)

(107)

(427)

(43)

(392)

(342)

(2,534)

 

(1,153)

 

December 31, 2016

17,786

940

1,659

771

4,921

7,357

33,434

 

14,309

 

Attributable to noncontrolling interests

 

150

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2016

220

-

7,903

-

16,461

-

24,584

 

5,867

 

 

Revisions

4

-

114

-

(183)

-

(65)

 

171

 

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

 

Purchases

-

-

-

-

-

-

-

 

-

 

 

Sales

-

-

-

-

-

-

-

 

-

 

 

Extensions/discoveries

-

-

5

-

-

-

5

 

1

 

 

Production

(13)

-

(398)

-

(1,044)

-

(1,455)

 

(374)

 

December 31, 2016

211

-

7,624

-

15,234

-

23,069

 

5,665

 

Total proved reserves at December 31, 2016

17,997

940

9,283

771

20,155

7,357

56,503

 

19,974

 

 

 

 

 

 

 

 

 

 

 

 

 

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2017

17,786

940

1,659

771

4,921

7,357

33,434

 

14,309

 

 

Revisions

649

206

134

(135)

(214)

33

673

 

1,063

 

 

Improved recovery

-

1

-

-

-

-

1

 

8

 

 

Purchases

982

56

-

-

-

-

1,038

 

771

 

 

Sales

(172)

(1)

(17)

-

-

-

(190)

 

(87)

 

 

Extensions/discoveries

956

269

-

-

13

-

1,238

 

970

 

 

Production

(1,168)

(99)

(408)

(41)

(380)

(496)

(2,592)

 

(1,131)

 

December 31, 2017

19,033

1,372

1,368

595

4,340

6,894

33,602

 

15,903

 

Attributable to noncontrolling interests

 

195

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2017

211

-

7,624

-

15,234

-

23,069

 

5,665

 

 

Revisions

25

-

(1,129)

-

86

-

(1,018)

 

(138)

 

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

 

Purchases

-

-

-

914

-

-

914

 

158

 

 

Sales

-

-

-

-

-

-

-

 

-

 

 

Extensions/discoveries

-

-

-

-

-

-

-

 

-

 

 

Production

(13)

-

(331)

-

(1,072)

-

(1,416)

 

(367)

 

December 31, 2017

223

-

6,164

914

14,248

-

21,549

 

5,318

 

Total proved reserves at December 31, 2017

19,256

1,372

7,532

1,509

18,588

6,894

55,151

 

21,221

 

 

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

115 


   

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

United

Other

 

 

 

Australia/

 

 

Total

 

 

States

Americas

Europe

Africa

Asia

Oceania

Total

 

All Products (1) 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

equivalent barrels)

Net proved developed and undeveloped

 

 

 

 

 

 

 

 

 

 

 

reserves of consolidated subsidiaries

 

 

 

 

 

 

 

 

 

 

January 1, 2018

19,033

1,372

1,368

595

4,340

6,894

33,602

 

15,903

 

 

Revisions

(98)

(29)

306

38

(147)

1,065

1,135

 

3,626

 

 

Improved recovery

-

-

-

-

-

-

-

 

36

 

 

Purchases

104

-

-

-

-

-

104

 

27

 

 

Sales

(264)

(3)

(4)

-

-

-

(271)

 

(71)

 

 

Extensions/discoveries

3,658

506

3

-

1

7

4,175

 

1,654

 

 

Production

(1,030)

(102)

(361)

(45)

(353)

(504)

(2,395)

 

(1,097)

 

December 31, 2018

21,403

1,744

1,312

588

3,841

7,462

36,350

 

20,078

 

Attributable to noncontrolling interests

 

334

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proportional interest in proved reserves

 

 

 

 

 

 

 

 

 

 

 

of equity companies

 

 

 

 

 

 

 

 

 

 

January 1, 2018

223

-

6,164

914

14,248

-

21,549

 

5,318

 

 

Revisions

12

-

(4,801)

(51)

102

-

(4,738)

 

(753)

 

 

Improved recovery

-

-

-

-

-

-

-

 

-

 

 

Purchases

-

-

-

-

-

-

-

 

-

 

 

Sales

-

-

(38)

-

-

-

(38)

 

(6)

 

 

Extensions/discoveries

2

-

-

-

-

-

2

 

1

 

 

Production

(12)

-

(268)

-

(1,029)

-

(1,309)

 

(345)

 

December 31, 2018

225

-

1,057

863

13,321

-

15,466

 

4,215

 

Total proved reserves at December 31, 2018

21,628

1,744

2,369

1,451

17,162

7,462

51,816

 

24,293

 

 

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

116 


   

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

Oil-Equivalent

 

 

 

United

Other

 

 

 

Australia/

 

 

Total

 

 

 

States

Americas

Europe

Africa

Asia

Oceania

Total

 

All Products (1) 

 

 

 

(billions of cubic feet)

 

(millions of oil-

 

 

 

 

 

equivalent barrels)

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

11,927

478

1,473

728

4,532

3,071

22,209

 

9,079

 

 

 

Equity companies

144

-

5,804

-

14,067

-

20,015

 

4,671

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

5,859

462

186

43

389

4,286

11,225

 

5,230

 

 

 

Equity companies

67

-

1,820

-

1,167

-

3,054

 

994

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2016

17,997

940

9,283

771

20,155

7,357

56,503

 

19,974

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

12,649

512

1,231

584

4,030

4,420

23,426

 

9,724

 

 

 

Equity companies

154

-

4,899

-

12,898

-

17,951

 

4,232

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

6,384

860

137

11

310

2,474

10,176

 

6,179

 

 

 

Equity companies

69

-

1,265

914

1,350

-

3,598

 

1,086

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2017

19,256

1,372

7,532

1,509

18,588

6,894

55,151

 

21,221

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

12,538

605

1,116

581

3,618

4,336

22,794

 

13,098

 

 

 

Equity companies

152

-

988

-

11,951

-

13,091

 

3,324

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved undeveloped reserves, as of

 

 

 

 

 

 

 

 

 

 

 

December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated subsidiaries

8,865

1,139

196

7

223

3,126

13,556

 

6,980

 

 

 

Equity companies

73

-

69

863

1,370

-

2,375

 

891

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total proved reserves at December 31, 2018

21,628

1,744

2,369

1,451

17,162

7,462

51,816

 

24,293

 

 

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

117 


   

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

 

Other

 

 

 

 

 

 

 

Australia/

 

 

Future Cash Flows

 

States

Americas (1) 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

118,283

 

50,243

 

15,487

 

40,734

 

118,997

 

28,877

 

372,621

 

 

Future production costs

 

65,585

 

29,798

 

5,362

 

14,447

 

38,727

 

7,643

 

161,562

 

 

Future development costs

 

31,744

 

11,735

 

9,235

 

8,833

 

13,088

 

8,177

 

82,812

 

 

Future income tax expenses

 

2,223

 

1,052

 

178

 

8,025

 

44,641

 

2,316

 

58,435

 

 

Future net cash flows

 

18,731

 

7,658

 

712

 

9,429

 

22,541

 

10,741

 

69,812

 

 

Effect of discounting net cash flows at 10%

 

11,039

 

3,443

 

(1,014)

 

2,790

 

12,848

 

5,556

 

34,662

 

 

Discounted future net cash flows

 

7,692

 

4,215

 

1,726

 

6,639

 

9,693

 

5,185

 

35,150

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

9,551

 

-

 

32,121

 

-

 

104,700

 

-

 

146,372

 

 

Future production costs

 

5,289

 

-

 

21,342

 

-

 

41,563

 

-

 

68,194

 

 

Future development costs

 

2,948

 

-

 

2,048

 

-

 

12,656

 

-

 

17,652

 

 

Future income tax expenses

 

-

 

-

 

2,206

 

-

 

16,622

 

-

 

18,828

 

 

Future net cash flows

 

1,314

 

-

 

6,525

 

-

 

33,859

 

-

 

41,698

 

 

Effect of discounting net cash flows at 10%

 

393

 

-

 

4,158

 

-

 

18,946

 

-

 

23,497

 

 

Discounted future net cash flows

 

921

 

-

 

2,367

 

-

 

14,913

 

-

 

18,201

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

8,613

 

4,215

 

4,093

 

6,639

 

24,606

 

5,185

 

53,351

 

(1)   Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of $706 million in 2016.

118 


   

 

 

 

 

 

 

 

Canada/

 

 

 

 

 

 

 

 

 

 

Standardized Measure of Discounted

 

United

 

Other

 

 

 

 

 

 

 

Australia/

 

 

Future Cash Flows (continued)

 

States

Americas (1) 

Europe

 

Africa

 

Asia

 

Oceania

 

Total

 

 

 

 

 

(millions of dollars)

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

186,126

 

78,870

 

14,794

 

43,223

 

191,254

 

40,814

 

555,081

 

 

Future production costs

 

78,980

 

42,280

 

4,424

 

14,049

 

53,723

 

8,424

 

201,880

 

 

Future development costs

 

39,996

 

18,150

 

7,480

 

8,897

 

15,156

 

7,951

 

97,630

 

 

Future income tax expenses

 

12,879

 

4,527

 

2,790

 

8,818

 

90,614

 

6,017

 

125,645

 

 

Future net cash flows

 

54,271

 

13,913

 

100

 

11,459

 

31,761

 

18,422

 

129,926

 

 

Effect of discounting net cash flows at 10%

 

30,574

 

6,158

 

(1,255)

 

2,996

 

17,511

 

8,741

 

64,725

 

 

Discounted future net cash flows

 

23,697

 

7,755

 

1,355

 

8,463

 

14,250

 

9,681

 

65,201

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

12,643

 

-

 

28,557

 

2,366

 

127,364

 

-

 

170,930

 

 

Future production costs

 

5,927

 

-

 

21,120

 

247

 

48,300

 

-

 

75,594

 

 

Future development costs

 

3,012

 

-

 

1,913

 

417

 

11,825

 

-

 

17,167

 

 

Future income tax expenses

 

-

 

-

 

1,683

 

514

 

22,396

 

-

 

24,593

 

 

Future net cash flows

 

3,704

 

-

 

3,841

 

1,188

 

44,843

 

-

 

53,576

 

 

Effect of discounting net cash flows at 10%

 

1,668

 

-

 

2,116

 

1,045

 

23,744

 

-

 

28,573

 

 

Discounted future net cash flows

 

2,036

 

-

 

1,725

 

143

 

21,099

 

-

 

25,003

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

25,733

 

7,755

 

3,080

 

8,606

 

35,349

 

9,681

 

90,204

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated Subsidiaries

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

265,527

 

204,596

 

23,263

 

47,557

 

241,410

 

67,041

 

849,394

 

 

Future production costs

 

96,489

 

125,469

 

5,023

 

16,019

 

61,674

 

18,081

 

322,755

 

 

Future development costs

 

54,457

 

29,759

 

7,351

 

8,356

 

13,907

 

8,047

 

121,877

 

 

Future income tax expenses

 

25,365

 

9,024

 

8,255

 

10,491

 

124,043

 

10,499

 

187,677

 

 

Future net cash flows

 

89,216

 

40,344

 

2,634

 

12,691

 

41,786

 

30,414

 

217,085

 

 

Effect of discounting net cash flows at 10%

 

49,176

 

22,315

 

(6)

 

2,957

 

21,509

 

15,030

 

110,981

 

 

Discounted future net cash flows

 

40,040

 

18,029

 

2,640

 

9,734

 

20,277

 

15,384

 

106,104

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity Companies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Future cash inflows from sales of oil and gas

 

17,730

 

-

 

7,264

 

3,777

 

165,471

 

-

 

194,242

 

 

Future production costs

 

6,474

 

-

 

2,157

 

249

 

61,331

 

-

 

70,211

 

 

Future development costs

 

3,359

 

-

 

1,165

 

370

 

10,295

 

-

 

15,189

 

 

Future income tax expenses

 

-

 

-

 

1,612

 

964

 

30,662

 

-

 

33,238

 

 

Future net cash flows

 

7,897

 

-

 

2,330

 

2,194

 

63,183

 

-

 

75,604

 

 

Effect of discounting net cash flows at 10%

 

4,104

 

-

 

713

 

1,712

 

31,503

 

-

 

38,032

 

 

Discounted future net cash flows

 

3,793

 

-

 

1,617

 

482

 

31,680

 

-

 

37,572

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total consolidated and equity interests in

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

standardized measure of discounted

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

future net cash flows

 

43,833

 

18,029

 

4,257

 

10,216

 

51,957

 

15,384

 

143,676

 

(1)   Includes discounted future net cash flows attributable to noncontrolling interests in ExxonMobil consolidated subsidiaries of  $1,016 million in 2017 and $2,823 million in 2018.

119 


   

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



 

Consolidated and Equity Interests

 

 

 

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2015

 

42,775

 

 

28,027

 

 

70,802

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

1,377

 

 

5

 

 

1,382

 

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

 

(17,110)

 

 

(5,540)

 

 

(22,650)

 

 

Development costs incurred during the year

 

9,905

 

 

1,438

 

 

11,343

 

 

Net change in prices, lifting and development costs (1) 

 

(26,561)

 

 

(15,549)

 

 

(42,110)

 

 

Revisions of previous reserves estimates

 

4,908

 

 

1,425

 

 

6,333

 

 

Accretion of discount

 

7,854

 

 

3,857

 

 

11,711

 

Net change in income taxes

 

12,002

 

 

4,538

 

 

16,540

 

 

 

Total change in the standardized measure during the year

 

(7,625)

 

 

(9,826)

 

 

(17,451)

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2016

 

35,150

 

 

18,201

 

 

53,351

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)     Securities and Exchange Commission (SEC) rules require the Corporation’s reserves to be calculated on the basis of average first-of-month oil and natural gas prices during the reporting year. As a result of very low prices during 2016, under the SEC definition of proved reserves, certain quantities of oil and natural gas that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2016. Future net cash flows for these quantities are excluded from the 2016 Standardized Measure of Discounted Future Cash Flows. Substantially all of this reduction in discounted future net cash flows since December 31, 2015, is reflected in the line “Net change in prices, lifting and development costs” in the table above.

  

 

Consolidated and Equity Interests

 

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2016

 

35,150

 

 

18,201

 

 

53,351

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

10,375

 

 

255

 

 

10,630

 

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

 

(24,911)

 

 

(7,358)

 

 

(32,269)

 

 

Development costs incurred during the year

 

7,066

 

 

2,020

 

 

9,086

 

 

Net change in prices, lifting and development costs

 

51,703

 

 

12,782

 

 

64,485

 

 

Revisions of previous reserves estimates

 

6,580

 

 

1,193

 

 

7,773

 

 

Accretion of discount

 

4,951

 

 

2,124

 

 

7,075

 

Net change in income taxes

 

(25,713)

 

 

(4,214)

 

 

(29,927)

 

 

 

Total change in the standardized measure during the year

 

30,051

 

 

6,802

 

 

36,853

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2017

 

65,201

 

 

25,003

 

 

90,204

 

120 


   

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



 

Consolidated and Equity Interests (continued)

 

 

 

 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

Share of

 

Consolidated

 

 

 

 

Consolidated

 

Equity Method

 

and Equity

 

 

 

 

Subsidiaries

 

Investees

 

Interests

 

 

 

 

(millions of dollars)

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2017

 

65,201

 

 

25,003

 

 

90,204

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

improved recovery and net purchases less related costs

 

9,472

 

 

(134)

 

 

9,338

 

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

 

(31,706)

 

 

(9,956)

 

 

(41,662)

 

 

Development costs incurred during the year

 

11,500

 

 

2,762

 

 

14,262

 

 

Net change in prices, lifting and development costs

 

56,798

 

 

23,582

 

 

80,380

 

 

Revisions of previous reserves estimates

 

14,515

 

 

(2,091)

 

 

12,424

 

 

Accretion of discount

 

8,793

 

 

3,043

 

 

11,836

 

Net change in income taxes

 

(28,469)

 

 

(4,637)

 

 

(33,106)

 

 

 

Total change in the standardized measure during the year

 

40,903

 

 

12,569

 

 

53,472

 

 

 

 

 

 

 

 

 

 

 

 

 

Discounted future net cash flows as of December 31, 2018

 

106,104

 

 

37,572

 

 

143,676

 

121 


OPERATING INFORMATION (unaudited)

 

 

 

2018

 

2017

 

2016

 

2015

 

2014

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

 

 

 

 

 

 

 

 

 

 

Net production

(thousands of barrels daily)

 

 

United States

551

 

514

 

494

 

476

 

454

 

 

Canada/Other Americas

438

 

412

 

430

 

402

 

301

 

 

Europe

132

 

182

 

204

 

204

 

184

 

 

Africa

387

 

423

 

474

 

529

 

489

 

 

Asia

711

 

698

 

707

 

684

 

624

 

 

Australia/Oceania

47

 

54

 

56

 

50

 

59

 

Worldwide

2,266

 

2,283

 

2,365

 

2,345

 

2,111

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas production available for sale

 

 

 

 

 

 

 

 

 

 

Net production

(millions of cubic feet daily)

 

 

United States

2,574

 

2,936

 

3,078

 

3,147

 

3,404

 

 

Canada/Other Americas

227

 

218

 

239

 

261

 

310

 

 

Europe

1,653

 

1,948

 

2,173

 

2,286

 

2,816

 

 

Africa

13

 

5

 

7

 

5

 

4

 

 

Asia

3,613

 

3,794

 

3,743

 

4,139

 

4,099

 

 

Australia/Oceania

1,325

 

1,310

 

887

 

677

 

512

 

Worldwide

9,405

 

10,211

 

10,127

 

10,515

 

11,145

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1) 

3,833

 

3,985

 

4,053

 

4,097

 

3,969

 

 

 

 

 

 

 

 

 

 

 

 

Refinery throughput

(thousands of barrels daily)

 

 

United States

1,588

 

1,508

 

1,591

 

1,709

 

1,809

 

 

Canada

392

 

383

 

363

 

386

 

394

 

 

Europe

1,422

 

1,510

 

1,417

 

1,496

 

1,454

 

 

Asia Pacific

706

 

690

 

708

 

647

 

628

 

 

Other Non-U.S.

164

 

200

 

190

 

194

 

191

 

Worldwide

4,272

 

4,291

 

4,269

 

4,432

 

4,476

Petroleum product sales (2) 

 

 

 

 

 

 

 

 

 

 

 

United States

2,210

 

2,190

 

2,250

 

2,521

 

2,655

 

 

Canada

510

 

499

 

491

 

488

 

496

 

 

Europe

1,556

 

1,597

 

1,519

 

1,542

 

1,555

 

 

Asia Pacific and other Eastern Hemisphere

1,200

 

1,164

 

1,140

 

1,124

 

1,085

 

 

Latin America

36

 

80

 

82

 

79

 

84

 

Worldwide

5,512

 

5,530

 

5,482

 

5,754

 

5,875

 

 

Gasoline, naphthas

2,217

 

2,262

 

2,270

 

2,363

 

2,452

 

 

Heating oils, kerosene, diesel oils

1,840

 

1,850

 

1,772

 

1,924

 

1,912

 

 

Aviation fuels

402

 

382

 

399

 

413

 

423

 

 

Heavy fuels

395

 

371

 

370

 

377

 

390

 

 

Specialty petroleum products

658

 

665

 

671

 

677

 

698

 

Worldwide

5,512

 

5,530

 

5,482

 

5,754

 

5,875

 

 

 

 

 

 

 

 

 

 

 

 

Chemical prime product sales (2) 

(thousands of metric tons)

 

 

United States

9,824

 

9,307

 

9,576

 

9,664

 

9,528

 

 

Non-U.S.

17,045

 

16,113

 

15,349

 

15,049

 

14,707

 

Worldwide

26,869

 

25,420

 

24,925

 

24,713

 

24,235

 

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

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

   

 

122 


INDEX TO EXHIBITS

Exhibit

Description

 

 

3(i)

Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for 2015).

 

 

3(ii)

By-Laws, as revised effective November 1, 2017 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K of October 31, 2017).

 

 

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 2017).*

 

 

10(iii)(a.2)

Extended Provisions for Restricted Stock Agreements (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2016).*

 

 

10(iii)(a.3)

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

 

 

10(iii)(b.1)

Short Term Incentive Program, as amended.*

 

 

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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).*

 

 

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.*

 

 

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 2016).*

 

 

10(iii)(f.1)

2004 Non-Employee Director Restricted Stock Plan.*

 

 

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 Annual Report on Form 10-K for 2016).*

 

 

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 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Annual Report on Form 10-K for 2015).*

 

 

14

Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2017).

 

 

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.

 

 

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.

 

123 


 

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/    DARREN W. WOODS        

 

 

(Darren W. Woods,

Chairman of the Board)

       

Dated February 27, 2019

     

 

 

 

  

 

POWER OF ATTORNEY

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

     

 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 27, 2019.

 

 

 

 

 

 

/s/    DARREN W. WOODS

 

Chairman of the Board

(Darren W. Woods)

 

(Principal Executive Officer)

 

 

 

/s/    SUSAN K. AVERY

 

Director

(Susan K. Avery)

 

 

 

 

 

/s/    ANGELA F. BRALY

 

Director

(Angela F. Braly)

 

 

 

 

 

/s/    URSULA M. BURNS

 

Director

(Ursula M. Burns)

 

 

 

 

 

124 


 

/s/    KENNETH C. FRAZIER

 

Director

(Kenneth C. Frazier)

 

 

 

 

 

/s/    STEVEN A. KANDARIAN

 

Director

(Steven A. Kandarian)

 

 

 

 

 

/s/    DOUGLAS R. OBERHELMAN

 

Director

(Douglas R. Oberhelman)

 

 

 

 

 

/s/    SAMUEL J. PALMISANO

 

Director

(Samuel J. Palmisano)

 

 

 

 

 

/s/    STEVEN S REINEMUND

 

Director

(Steven S Reinemund)

 

 

 

 

 

/s/    WILLIAM C. WELDON

 

Director

(William C. Weldon)

 

 

 

 

 

/s/    ANDREW P. SWIGER

 

Senior Vice President

(Andrew P. Swiger)

 

(Principal Financial Officer)

 

 

 

/s/    DAVID S. ROSENTHAL

 

Vice President and Controller

(David S. Rosenthal)

 

(Principal Accounting Officer)

 

 

 

 

125