20181126012437bus_402_week_2_assignment x20181126012434bus402_strategic_plan_template x20181126012408exxon_annual_10k_report
Prior to completing this assignment, review your prior research and course submissions related to the company you selected for research in Week 2’s Environmental Scanning interactive assignment. Ensure that you have incorporated the feedback you received from your previous submissions. In your Final Project this week, you will pull the various elements you’ve created together to aid your creation of a Strategic Plan. From the perspective of an executive with the firm, your supervisor has tasked you with creating a strategic plan to grow the business over the next three years using this
Strategic Plan Template
. Continue to access the Mergent Ashford University Library online database which offers company financials, descriptions, history, property, subsidiaries, officers, and directors and the Business Insights database. (View the
Mergent tipsheet
and Business Insights tipsheet Tips document for suggested methods of searching Ashford University Library databases generally as well as specific advice for searching these two databases).
Your strategic plan must be future-oriented and must
- Describe the company, the company’s history and its 4Ps (Product, Price, Place, and Promotion).
- Examine the company’s mission statement and assess its impact on the organization’s activities.
- Explain the current situation of the organization in the market (industry, market, and general environment analysis).
- Add your SWOT analysis (strengths, weaknesses, opportunities, and threats) of your chosen company here. Evaluate areas that offer opportunities for
Choose three or four areas from your SWOT analysis and assess why the areas you have chosen are essential to your strategic plan
- Summarize the results of your Environmental Scan and Porter’s 5 Forces.
Evaluate the degree to which they aid in conceptualizing the company’s competitive position in its marketplace.
- Assess the company’s international performance in light of Cultural Barriers, Monetary Exchange Rates, and Political Instability.
- Assess the financial performance and condition of the
- Operational budget: Research and assess the company’s operational budget.
- Assess the performance in terms of key performance indicators.
- In your analysis, be sure to include profitability ratios relevant to your analysis.
Debt to Equity ratio
Debt to Assets ratio - Based on the data, evaluate the overall current financial condition of the company.
Support your analysis by referring to the company data
Create a three year end trend analysis - Assess how your Operational Budget analysis affects your three-year strategic plan.
- Recommend an organizational structure in terms of the organizational design as defined in Abraham (2012) section 2.6.
- Assess the impact of the strategic plan on the organizational culture.
- Strategic Goals: Create measurable core strategic goals for each of the three to four areas addressed from the SWOT analysis, addressing any contingencies associated with the strategies you are recommending and prioritizing them according to ease of achievement and time to completion.
- Recommend marketing positions and opportunities for growth in your strategic plan
- Add specific language to the strategic plan that addresses the company’s Corporate Social Responsibility
- Explain your plan to measure the success of your strategic
- Submit the Strategic Plan to the instructor.
The Final Paper
Title of paper
Student’s name
Course name and number
Instructor’s name
Date submitted
Must use at least five scholarly and/or credible resources (including a minimum of three from the Ashford University Library) other than the textbook. Use the Scholarly, Peer Reviewed, and Other Credible Sources (Links to an external site.)Links to an external site ument for guidance.
Note : My chosen company Topic is ExxonMobil which i have used in my week assignment. i am also attaching some document which will be helpful to complete the assignment
Running Head:
PORSCHE GROUP FINANCIAL AND SWOT REPORT 1
Running Head: PORSCHE GROUP FINANCIAL AND SWOT REPORT 7
Porsche Group Financial and SWOT Analysis
Vishal Kumar Upadhyay
BUS402: Strategic Management and Business Policy
Instructor: Earl Levith
November 5th, 2018
Financial Overview and SWOT Analysis of the Porsche SE Group
The Porsche name is synonymous with high performance sports cars. But there is much more to this company than producing their most visible product. The Porsche SE Group is an automobile manufacturing company that not only produces vehicles under the Porsche brand, but also produces a variety of brands that fall under the Volkswagen umbrella of the company. From Porsche’s beginnings as an automobile design and engineering business, it has grown to be one of the largest automobile manufacturers in the world. The purpose of this essay, in this context, is to assess the financial performance and condition of the Porsche SE Group, along with providing an analysis of the strengths, weaknesses, opportunities, and threats (SWOT) in relation to this company. In addition, company decisions will be analyzed for quality. Finally, recommendations for improving the company will be provided. To provide background, the first thing to be addressed is the company’s history.
HISTORY
As stated in the introduction, Dr. Ferdinand Porsche founded Porsche as an automobile design and engineering company in Germany in 1930 (History of Porsche – Funding Universe, nd.). Dr. Porsche’s reputation for innovative car designs did not go unnoticed, attracting the attention of Adolf Hitler. The collaboration between Porsche and Hitler resulted in the 1939 production of the Type 60 KdF-Wagen (Price, 2006). Porsche, who designed this car, preferred to call it the Volkswagen, or “people’s car (Price, 2006). The German people, however, referred to the car as the Beetle, the iconic name that the car is known as to this day (Price, 2006). While the early history of the company may be controversial, Porsche moved on to start manufacturing by 1948 its own “expensive, handmade, high performance sports car” (History of Porsche – Funding Universe, nd.). Using the design of the Volkswagen Beetle as a platform, Porsche started production of a handmade lightweight sports car, making five cars a month (History of Porsche – Funding Universe, nd.).
By 1956, Porsche had produced its 10,000 car (History of Porsche – Funding Universe, nd.). As the Porsche Company entered the 1960’s, it developed its most iconic and popular sports car, the 911. Introduced in 1964, the 911 was a two-seat sports car that had a rear mounted air-cooled flat engine, and featured a “low waistline and expanded glass areas [that] gave the new design a more elegant look” (History of Porsche – Funding Universe, nd.). The decades of the 1970’s and 1980’s saw the export market grow for Porsche, with Japan and the United States being major customers. In fact, 70% of the vehicles manufactured in 1981 at the Stuttgart plant were exported, with the United States accounting for almost 40% of Porsche’s total sales (History of Porsche – Funding Universe, nd.) By the 1990’s the export market for Porsche had collapsed, with over 30,000 sports cars sold in the United States in 1986, dropping to only 4,133 sports cars sold by 1992 (History of Porsche – Funding Universe, nd.). Porsche reacted to this by hiring a new CEO in 1992 who was charged with reducing costs and increasing efficiency (History of Porsche – Funding Universe, nd.). This had the desired outcome, with care sales rebounding in the United States rebounding to over 18,000 in 1998 (History of Porsche – Funding Universe, nd.). In 2005, Porsche expanded its footprint by merging with Volkswagen, in an effort to leverage Volkswagen’s resources in the joint development of new technologies (Ewing, 2005).
FINANCIALS
Since merging with Volkswagen in 2005, the Porsche Group seems to be on sound financial footing. One method to determine the financial health of a company is by using financial ratios, which pinpoints “ratios of key financial statement accounts that are helpful in identifying financial performance that merits further analysis” (Hickman, Byrd & McPherson, 2013). One area to look out when using financial ratios is liquidity. In regards to the Porsche Group’s liquidity, the current ratio and quick ratio will be examined. The current ratio is a measure of short-term debt paying capacity (Hickman, Byrd & McPherson, 2013). The formula for current ratio is the company’s current assets divided by current liabilities. With this rate, the higher the number the better. For the Porsche Group, the rate as of December 2013 was 6.48 (Mergent Online, 2013). In comparison, Ford Motors current ratio was only .60 during the same time frame (Mergent Online, 2013). The quick ratio formula, which measures short-term liquidity, is current assets minus inventory divided by current liabilities (Hickman, Byrd & McPherson, 2013). The quick ratio as of December 2013 for the Porsche Group was 6.48 (Mergent Online, 2013). Once again, in comparison, Ford Motors quick ratio was .49 during this time frame (Mergent Online, 2013). Another area of financial health to look at is long term debt. As of December 2013, the Porsche Group had no long term debt (Mergent Online, 2013). Using Ford in comparison again, 54.32% of its invested capital was long term debt (Mergent Online, 2013). Working capital is another area that indicates financial health. To determine working capital, the current liabilities are subtracted from the current assets (Hickman, Byrd & McPherson, 2013). The ratio for this measure is current assets / current liabilities, with a rate over 1 being considered positive (Hickman, Byrd & McPherson, 2013). Using this formula, Porsche has a working capital rate of 6.81 as of December 2013 (Mergent Online, 2013). Ford’s rate for the same time frame was .59 (Mergent Online, 2013). While not all financial indicators were looked at, the ones that were showed the Porsche Group to be sound financially at this point, especially when compared to the Ford Motor Company.
SWOT ANALYSIS
STRENGTHS
Engineering and Design – Porsche is renowned for its engineering and design in the automotive industry. Under the Porsche Engineering Group (PEG), the company has shared its research and development (R&D) capabilities with outside companies (Henderson & Reavis, 2009). Since merging with Volkswagen, Porsche now has the ability “draw on Volkswagen’s resources as they jointly develop new technology, such as gasoline-electric hybrid technology” (Ewing, 2005). Financials – Porsche continues to be sound financially. This is illustrated by the fact that Porsche leads the industry on profit per unit basis. Porsche’s average revenue per car was $91,974 in 2007 (Henderson & Reavis, 2009). Also in 2007, the companies income “income topped $9.4 billion on revenue of $10 billion” (Henderson & Reavis, 2009).
Quality – J.D Power and Associates rated Porsche the top brand in “Initial Quality Study” (based on fewest problems per 100 vehicles) for 2006-2008 (Henderson & Reavis, 2009). Porsche spends 12% of revenue on R&D, while the rest of industry only averages about 5% on R&D (Henderson & Reavis, 2009).
WEAKNESSES
Porsche’s merging with Volkswagen could possibly dilute the Porsche brand. Customers have concerns over outsourcing assembly and engineering to Volkswagen facilities. Collaboration on the Porsche Cayenne and Volkswagen Touareg has highlighted these concerns. While the Volkswagen portion of the company has an abundant production of vehicles, the Porsche brand could suffer because of the limited amount of vehicles produced, along with the price sensitivity of the high performance sports car market. Another weakness is the fact that Porsche vehicles use premium gas only.
OPPORTUNITIES
While collaboration with Volkswagen on the Touareg was listed as a weakness, the Porsche Cayenne has been a success. Porsche can make inroads into the SUV market if it can leverage the success of the Cayenne into both larger and smaller vehicles. Porsche can also capitalize on the hybrid technology of Volkswagen by introducing this technology into the sports car platform. This will, in turn, have the effect of positioning Porsche as an environmentally friendly company.
THREATS
The external threats to the Porsche Group will continue to be governmental policies, competitors, the economy, and natural disasters. Internally, the company has to guard against brand deterioration. In other words, a Porsche must remain a Porsche, and a Volkswagen must remain a Volkswagen. While collaboration between the brands can be beneficial, too much cross-pollination will dilute the characteristics that make each brand unique.
RECOMMENDATIONS
In the mid-1980s through the mid-1990s, the Porsche Company was about to go through bankruptcy (Henderson & Reavis, 2009). A new CEO took over and turned the company around, emphasizing lean manufacturing and building new core competencies (Henderson & Reavis, 2009). As this turnaround has shown, the way forward for Porsche is to focus on Total Quality Management, lean manufacturing, and staying true to the brand. By concentrating on the core competencies and values of the Porsche brand, the company can stay viable well into the future. In turn, the Porsche Group must let Volkswagen and its brands continue to define their own identity. Maintaining brand identity, while continuing to synergize on processes and technology, will be a challenge for Porsche.
References :
Ewing, J. (2005). Porsche’s Risky Ride with VW. Businessweek Online. Retrieved on September 29, 2014 from http://web.b.ebscohost.com.proxy-library.ashford.edu/ehost/ detail/detail?vid=10&sid=73bd0608-929a-45ce-bd81-8c848a12ae10%40sessionmgr 198&hid=126&bdata=JkF1dGhUeXBlPWlwLGNwaWQmY3VzdGlkPXM4ODU2ODk3 JnNpdGU9ZWhvc3QtbGl2ZQ%3d%3d#db=bsh&AN=18460466
Henderson, R., & Reavis, C. (2009). What’s Driving Porsche? Retrieved on September 28, 2014 from https://mitsloan.mit.edu/LearningEdge/CaseDocs/08-075- What%27s%20Driving%20Porsche.Henderson
Hickman, K. A., Byrd, W. J., & McPherson, M. (2013). Essentials of Finance. San Diego: Bridgepoint Education, Inc. Retrieved on September 28, 2014 from https://content.ashford.edu/books/AUBUS401.13.1/
History of Porsche AG – FundingUniverse, (n.d.). Retrieved on September 28, 2014 from http://www.fundinguniverse.com/company-histories/porsche-ag-history/
Mergent Online, (2013). Ford Motor Co. Financial Highlights as of 12/31/2013. Retrieved on September 29, 2013 from http://www.mergentonline.com.proxy-library.ashford.edu/ companydetail.php?pagetype=highlights&compnumber=3424
Mergent Online, (2013). Porsche Automobile Holding SE. Financial Highlights as of 12/31/2013. Retrieved on September 29, 2013 from http://www.mergentonline.com. proxy-library.ashford.edu/companydetail.php?pagetype=highlights&compnumber=32767
Price, R. (2006). The Beetle in Battle. World War II [serial online]. May 2006; 21(2):58-64. Retrieved on September 28, 2014 from http://web.b.ebscohost.com.proxy- library.ashford.edu/ehost/pdfviewer/pdfviewer?sid=73bd0608-929a-45ce-bd81- 8c848a12ae10%40sessionmgr198&vid=6&hid=126
Running head: THREE YEAR STRATEGIC PLAN 1
THREE YEAR STRATEGIC PLAN 3
Three Year Strategic Plan
Name
Course Name
Instructor’s Name
Date
Hint: In this template, you will find purple and orange “hint” boxes designed to help you with the project. Please delete all hints before finalizing your strategic plan.
Three Year Strategic Plan
Hint: Keep bold headings in the template. Delete text in the boxes and replace with your own content. The boxes will expand as you type if you need more space.
Executive Summary
Company History
|
In this space describe the company’s history. Include the 4Ps (Product, Price, Place, and Promotion. |
Mission Statement
|
In this space, share the mission statement of the company and assess its impact. |
Situational Analysis
Current Situation
|
In this space, explain the current situation of the organization (industry, market, and general environment analysis). |
Hint: For help, see the SWOT Analysis Guide.
SWOT Analysis
|
In this space, assess the SWOT analysis (strengths, weaknesses, opportunities, and threats) of the chosen company highlighting opportunities for change and address contingencies. |
Environmental Scan and Porter’s 5 Forces
|
In this space, summarize the results of your Environmental Scan and Porter’s 5 Forces, evaluating the degree to which they aid in conceptualizing the company’s competitive position in its marketplace. |
International Performance
|
In this space, assess the company’s international performance in light of cultural barriers, monetary exchange rates, and political instability. |
Operational Planning
Financial Performance
|
In this space, analyze the financial performance and condition of the organization. |
Operational Budget and Assessment
|
In this space, discuss the Operational Budget and Assessment using key ratios and performance indicators. |
Strategic Goals: Core Strategies and Tactics
Strategic Goals
|
In this space, share measurable core strategic goals for each of the three to four areas identified from the SWOT analysis, including contingencies. |
Prioritized Core Strategies
In this space, prioritize the core strategies, estimating the ease of achievement and time to completion.
Recommended Organizational Structure
In this space, recommend an organizational structure assessing the impact of the strategic plan on organizational culture.
Recommended Marketing Positions
In this space, recommend marketing positions and opportunities for growth.
Measuring Success
In this space, explain plans to measure the success of the strategic plan.
Hint: Before finalizing your document, be sure to carefully proofread. For help, see these
Proofreading Tips
.
2017
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, 2017
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 (4,237,462,159 shares outstanding at January 31, 2018) New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that
the registrant was required to submit and post such files). Yes No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-
K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or 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 30, 2017, the last business day of the registrant’s
most recently completed second fiscal quarter, based on the closing price on that date of $80.73 on the New York Stock Exchange composite tape,
was in excess of $342 billion.
Documents Incorporated by Reference: Proxy Statement for the 2018 Annual Meeting of Shareholders (Part III)
[THIS PAGE INTENTIONALLY LEFT BLANK]
EXXON MOBIL CORPORATION
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017
TABLE OF CONTENTS
PART I
Item 1. Business 1
Item 1A. Risk Factors 2
Item 1B. Unresolved Staff Comments 4
Item 2. Properties 5
Item 3. Legal Proceedings 26
Item 4. Mine Safety Disclosures 26
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] 27
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities 30
Item 6. Selected Financial Data 30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 31
Item 8. Financial Statements and Supplementary Data 31
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 31
Item 9A. Controls and Procedures 31
Item 9B. Other Information 31
PART III
Item 10. Directors, Executive Officers and Corporate Governance 32
Item 11. Executive Compensation 32
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters 32
Item 13. Certain Relationships and Related Transactions, and Director Independence 33
Item 14. Principal Accounting Fees and Services 33
PART IV
Item 15. Exhibits, Financial Statement Schedules 33
Item 16. Form 10-K Summary 33
Financial Section 34
Index to Exhibits 120
Signatures 121
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges
Exhibit 18 — Preferability Letter
Exhibits 31 and 32 — Certifications
[THIS PAGE INTENTIONALLY LEFT BLANK]
1
PART I
ITEM 1. BUSINESS
Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil
operate or market products in the United States and most other countries of the world. Their principal business is energy, involving
exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of
crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals,
including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. Affiliates of
ExxonMobil conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso,
Mobil or XTO. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso, Mobil and XTO, as well as terms
like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of
affiliates. The precise meaning depends on the context in question.
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. Information on Company-sponsored research and
development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report.
ExxonMobil held over 12 thousand active patents worldwide at the end of 2017. For technology licensed to third parties, revenues
totaled approximately $89 million in 2017. 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 69.6 thousand, 71.1 thousand, and 73.5 thousand at years ended 2017, 2016 and 2015,
respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who
work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees
do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 1.6 thousand,
1.6 thousand, and 2.1 thousand at years ended 2017, 2016 and 2015, respectively.
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 2017
worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity
company expenditures, were $4.7 billion, of which $3.3 billion were included in expenses with the remainder in capital
expenditures. The total cost for such activities is expected to increase to approximately $5 billion in 2018 and 2019. 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.
2
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, which affect the demand for energy
associated with heating and cooling; increased competitiveness of alternative energy sources that have so far generally not been
competitive with oil and gas without the benefit of government subsidies or mandates; 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 member countries to OPEC production quotas and the occurrence of wars, hostile actions,
natural disasters, disruptions in competitors’ operations, or unexpected unavailability of distribution channels that may disrupt
supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to
manufacture petrochemicals.
Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest
rates, inflation, currency exchange rates, and other local or regional market conditions.
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.
3
Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain
exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our
results, such as:
increases in taxes, 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, or hydraulic
fracturing);
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, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable
energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand
for hydrocarbons, as well as shift hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and
pending greenhouse gas regulations 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.
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
4
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. To maintain our competitive position, especially in light of the technological nature of our businesses
and the need for continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful
and able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas
emissions.
Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the
inherent risks of oil, gas, and petrochemical operations, to control effectively our business activities, and to minimize the potential
for human error. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other
adverse environmental events. For example, we work to minimize spills through a combined program of effective operations
integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly,
we are implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not only in
response to government requirements but also to address community priorities. We also maintain a disciplined framework of
internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities
and other adverse impacts could result if our management systems and controls do not function as intended.
Cybersecurity. ExxonMobil is regularly subject to attempted cybersecurity disruptions from a variety of threat actors. If our
systems for protecting against cybersecurity disruptions prove to be insufficient, ExxonMobil as well as our customers, employees,
or third parties could be adversely affected. Such 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 such a cybersecurity disruption as well as in connection with resulting regulatory actions
and litigation.
Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For
example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas.
Our facilities are designed, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety
factors built in to cover a number of engineering uncertainties, including those associated with wave, wind, and current intensity,
marine ice flow patterns, permafrost stability, storm surge magnitude, temperature extremes, extreme rain fall events, and
earthquakes. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering
uncertainties that climate change and other events may potentially introduce. Our ability to mitigate the adverse impacts of these
events depends in part upon the effectiveness of our robust facility engineering as well as our rigorous disaster preparedness and
response and business continuity planning.
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.
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.
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 2017
The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated
subsidiaries and equity companies. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during
the last 12-month period. No major discovery or other favorable or adverse event has occurred since December 31, 2017, that would
cause a significant change in the estimated proved reserves as of that date.
Crude Natural Gas Synthetic Natural Oil-Equivalent
Oil Liquids Bitumen Oil Gas Basis
(million bbls) (million bbls) (million bbls) (million bbls) (billion cubic ft) (million bbls)
Proved Reserves
Developed
Consolidated Subsidiaries
United States 1,137 352 – – 12,649 3,597
Canada/Other Americas (1) 85 7 657 473 512 1,307
Europe 93 26 – – 1,231 325
Africa 593 83 – – 584 773
Asia 2,070 112 – – 4,030 2,854
Australia/Oceania 85 46 – – 4,420 868
Total Consolidated 4,063 626 657 473 23,426 9,724
Equity Companies
United States 201 7 – – 154 234
Europe 14 – – – 4,899 830
Africa – – – – – –
Asia 715 304 – – 12,898 3,168
Total Equity Company 930 311 – – 17,951 4,232
Total Developed 4,993 937 657 473 41,377 13,956
Undeveloped
Consolidated Subsidiaries
United States 1,558 609 – – 6,384 3,231
Canada/Other Americas (1) 325 12 355 – 860 835
Europe 26 4 – – 137 53
Africa 136 1 – – 11 139
Asia 1,426 – – – 310 1,478
Australia/Oceania 25 6 – – 2,474 443
Total Consolidated 3,496 632 355 – 10,176 6,179
Equity Companies
United States 44 4 – – 69 60
Europe 1 – – – 1,265 212
Africa 6 – – – 914 158
Asia 382 49 – – 1,350 656
Total Equity Company 433 53 – – 3,598 1,086
Total Undeveloped 3,929 685 355 – 13,774 7,265
Total Proved Reserves 8,922 1,622 1,012 473 55,151 21,221
(1) Other Americas includes proved developed reserves of 2 million barrels of crude oil and 42 billion cubic feet of natural gas,
as well as proved undeveloped reserves of 150 million barrels of crude oil and 175 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 2017
Additions to ExxonMobil’s proved reserves in 2017 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 and has a degree in Engineering. He
is an active member 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,
and a member currently serves on the SPE Oil and Gas Reserves Committee.
The Global Reserves group maintains a central database containing the official company reserves estimates. Appropriate controls,
including limitations on database access and update capabilities, are in place to ensure data integrity within this central database.
An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include
technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the
reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless
these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In
addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level
of management within the operating organization before the changes may be made in the central database. Endorsement by the
Global Reserves group for all proved reserves changes is a mandatory component of this review process. After all changes are
made, reviews are held with senior management for final endorsement.
7
2. Proved Undeveloped Reserves
At year-end 2017, approximately 7.3 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as
proved undeveloped. This represents 34 percent of the 21.2 GOEB reported in proved reserves. This compares to the 6.2 GOEB of
proved undeveloped reserves reported at the end of 2016. During the year, ExxonMobil conducted development activities that
resulted in the transfer of approximately 0.7 GOEB from proved undeveloped to proved developed reserves by year-end. The largest
transfers were related to the start-up of the Gorgon field and Longford Gas Conditioning Plant in Australia and drilling activity in
the United States, the United Arab Emirates, and Kazakhstan. During 2017, extensions and discoveries, primarily in the United
Arab Emirates, the United States, and Guyana resulted in an addition of approximately 0.9 GOEB of proved undeveloped reserves.
Also, purchases, primarily in the United States and Mozambique resulted in the addition of approximately 0.9 GOEB of proved
undeveloped reserves.
Overall, investments of $8 billion were made by the Corporation during 2017 to progress the development of reported proved
undeveloped reserves, including $8 billion for oil and gas producing activities and in addition, nearly $100 million for other non-
oil and gas producing activities such as the construction of support infrastructure and other related facilities. These investments
represented 48 percent of the $16.7 billion in total reported Upstream capital and exploration expenditures. Investments made by
the Corporation to develop quantities which no longer meet the SEC definition of proved reserves due to 2017 average prices are
included in the $16.7 billion of Upstream capital expenditures reported above but are excluded from amounts related to progressing
the development of proved undeveloped reserves.
One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments
toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long
lead-time in order to be developed. Development projects typically take 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 Canada, Kazakhstan, Australia, the Netherlands, the United States, and Qatar 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, 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 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. In Australia, proved undeveloped reserves are associated with future compression for the
Gorgon Jansz LNG project. In the Netherlands, the Groningen gas field has proved undeveloped reserves related to installation of
future compression.
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.
2017 2016 2015
(thousands of barrels daily)
Crude oil and natural gas liquids production Crude Oil NGL Crude Oil NGL Crude Oil NGL
Consolidated Subsidiaries
United States 361 96 347 87 326 86
Canada/Other Americas 44 6 53 6 47 8
Europe 147 31 171 31 173 28
Africa 412 11 459 15 511 18
Asia 373 26 383 27 346 29
Australia/Oceania 35 19 37 19 33 17
Total Consolidated Subsidiaries 1,372 189 1,450 185 1,436 186
Equity Companies
United States 55 2 58 2 61 3
Europe 4 – 2 – 3 –
Asia 235 64 232 65 241 68
Total Equity Companies 294 66 292 67 305 71
Total crude oil and natural gas liquids production 1,666 255 1,742 252 1,741 257
Bitumen production
Consolidated Subsidiaries
Canada/Other Americas 305 304 289
Synthetic oil production
Consolidated Subsidiaries
Canada/Other Americas 57 67 58
Total liquids production 2,283 2,365 2,345
(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States 2,910 3,052 3,116
Canada/Other Americas (1) 218 239 261
Europe 1,046 1,093 1,110
Africa 5 7 5
Asia 906 927 1,080
Australia/Oceania 1,310 887 677
Total Consolidated Subsidiaries 6,395 6,205 6,249
Equity Companies
United States 26 26 31
Europe 902 1,080 1,176
Asia 2,888 2,816 3,059
Total Equity Companies 3,816 3,922 4,266
Total natural gas production available for sale 10,211 10,127 10,515
(thousands of oil-equivalent barrels daily)
Oil-equivalent production 3,985 4,053 4,097
(1) Other Americas includes natural gas production available for sale for 2017, 2016 and 2015 of 24 million, 22 million, and
21 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 2017 (dollars per unit)
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
During 2016
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
10
Canada/
United Other Australia/
States Americas Europe Africa Asia Oceania Total
During 2015 (dollars per unit)
Consolidated Subsidiaries
Average production prices
Crude oil, per barrel 41.87 44.30 49.04 51.01 48.30 49.56 47.75
NGL, per barrel 16.96 21.91 27.50 33.41 21.14 29.75 22.16
Natural gas, per thousand cubic feet 1.65 1.78 6.47 1.57 2.02 5.13 2.95
Bitumen, per barrel – 25.07 – – – – 25.07
Synthetic oil, per barrel – 48.15 – – – – 48.15
Average production costs, per oil-equivalent barrel – total 12.50 22.68 15.86 10.31 7.71 8.86 12.97
Average production costs, per barrel – bitumen – 19.20 – – – – 19.20
Average production costs, per barrel – synthetic oil – 41.83 – – – – 41.83
Equity Companies
Average production prices
Crude oil, per barrel 46.34 – 46.05 – 48.44 – 47.99
NGL, per barrel 15.37 – – – 32.36 – 31.75
Natural gas, per thousand cubic feet 2.05 – 6.27 – 5.83 – 5.92
Average production costs, per oil-equivalent barrel – total 22.15 – 7.75 – 1.41 – 3.89
Total
Average production prices
Crude oil, per barrel 42.58 44.30 48.97 51.01 48.36 49.56 47.79
NGL, per barrel 16.92 21.91 27.50 33.41 28.94 29.75 24.77
Natural gas, per thousand cubic feet 1.65 1.78 6.37 1.57 4.84 5.13 4.16
Bitumen, per barrel – 25.07 – – – – 25.07
Synthetic oil, per barrel – 48.15 – – – – 48.15
Average production costs, per oil-equivalent barrel – total 13.16 22.68 13.09 10.31 3.96 8.86 10.56
Average production costs, per barrel – bitumen – 19.20 – – – – 19.20
Average production costs, per barrel – synthetic oil – 41.83 – – – – 41.83
Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor.
Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and
natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The
volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in
section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas
Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial
Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per
one thousand barrels.
11
4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
2017 2016 2015
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States – – –
Canada/Other Americas 5 2 1
Europe – 1 1
Africa 1 1 1
Asia – – 2
Australia/Oceania – – 1
Total Consolidated Subsidiaries 6 4 6
Equity Companies
United States – – –
Europe – 1 1
Africa – – –
Asia – – –
Total Equity Companies – 1 1
Total productive exploratory wells drilled 6 5 7
Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States – – 1
Canada/Other Americas – 1 –
Europe – – 2
Africa 2 1 –
Asia – – –
Australia/Oceania – – –
Total Consolidated Subsidiaries 2 2 3
Equity Companies
United States – – 1
Europe – – 1
Africa – – –
Asia 1 – –
Total Equity Companies 1 – 2
Total dry exploratory wells drilled 3 2 5
12
2017 2016 2015
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States 300 335 692
Canada/Other Americas 12 13 53
Europe 6 9 10
Africa 6 7 23
Asia 15 13 14
Australia/Oceania 1 – 4
Total Consolidated Subsidiaries 340 377 796
Equity Companies
United States 154 121 390
Europe 1 2 1
Africa – – –
Asia 3 3 2
Total Equity Companies 158 126 393
Total productive development wells drilled 498 503 1,189
Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States 4 2 5
Canada/Other Americas – – –
Europe 1 2 3
Africa – – 1
Asia – – –
Australia/Oceania – – –
Total Consolidated Subsidiaries 5 4 9
Equity Companies
United States – – –
Europe – – –
Africa – – –
Asia – – –
Total Equity Companies – – –
Total dry development wells drilled 5 4 9
Total number of net wells drilled 512 514 1,210
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 2017, the company’s share of net production of synthetic crude oil was about 57 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 produced
from open-pit mining operations, and processed through bitumen extraction and froth treatment trains. The product, a blend of
bitumen and diluent, is shipped to our refineries and to other third parties. Diluent is natural gas condensate or other light
hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail. During 2017, average net production at
Kearl was about 174 thousand barrels per day.
5. Present Activities
A. Wells Drilling
Year-End 2017 Year-End 2016
Gross Net Gross Net
Wells Drilling
Consolidated Subsidiaries
United States 820 334 760 302
Canada/Other Americas 30 22 22 17
Europe 12 2 12 3
Africa 10 2 30 7
Asia 58 15 38 11
Australia/Oceania 3 1 4 1
Total Consolidated Subsidiaries 933 376 866 341
Equity Companies
United States 10 1 22 3
Europe 8 3 9 4
Asia 14 4 7 2
Total Equity Companies 32 8 38 9
Total gross and net wells drilling 965 384 904 350
B. Review of Principal Ongoing Activities
UNITED STATES
ExxonMobil’s year-end 2017 acreage holdings totaled 12.8 million net acres, of which 0.9 million net acres were offshore.
ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.
During the year, 444.9 net 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. In 2017, ExxonMobil acquired a number of oil and
gas properties in the Permian Basin.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2017 was 0.8 million acres. A total of 2.3 net development wells were
completed during the year.
Participation in Alaska production and development continued with a total of 10.9 net development wells completed.
14
CANADA / OTHER AMERICAS
Canada
Oil and Gas Operations: ExxonMobil’s year-end 2017 acreage holdings totaled 6.5 million net acres, of which 3.2 million net acres
were offshore. A total of 10.8 net development wells were completed during the year. The Hebron project started up in 2017.
In Situ Bitumen Operations: ExxonMobil’s year-end 2017 in situ bitumen acreage holdings totaled 0.7 million net onshore acres.
Argentina
ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end 2017, and there were 4.0 net exploration and development
wells completed during the year.
Guyana
ExxonMobil’s net acreage totaled 5.2 million offshore acres at year-end 2017, and there were 2.3 net exploration wells completed
during the year. The Liza Phase 1 project was funded in 2017.
EUROPE
Germany
A total of 2.8 million net onshore acres were held by ExxonMobil at year-end 2017, with 1.3 net development wells completed
during the year.
Netherlands
ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2017, of which 1.1 million acres were
onshore. A total of 1.3 net exploration and development wells were completed during the year.
Norway
ExxonMobil’s net interest in licenses at year-end 2017 totaled approximately 0.1 million acres, all offshore. A total of 3.9 net
development wells were completed during the year. In 2017, ExxonMobil divested approximately 81 thousand net operated acres
in Norway.
United Kingdom
ExxonMobil’s net interest in licenses at year-end 2017 totaled approximately 0.6 million acres, all offshore. A total of 1.2 net
exploration and development wells were completed during the year. The Penguins Redevelopment project was funded in 2017.
AFRICA
Angola
ExxonMobil’s net acreage totaled 0.2 million offshore acres at year-end 2017, with 5.9 net development wells completed during
the year. On Block 32, development activities continued on the Kaombo Split Hub project.
Chad
ExxonMobil’s net year-end 2017 acreage holdings consisted of 46 thousand onshore acres.
Equatorial Guinea
ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2017, with 2.4 net exploration wells completed during the
year.
Mozambique
ExxonMobil’s net acreage totaled approximately 0.1 million offshore acres at year-end 2017. ExxonMobil acquired an interest in
Area 4 offshore Mozambique in December 2017. The Coral South Floating LNG project was funded in 2017.
Nigeria
ExxonMobil’s net acreage totaled 1.1 million offshore acres at year-end 2017, with 0.8 net development wells completed during
the year.
15
ASIA
Azerbaijan
At year-end 2017, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 1.3 net development wells were completed
during the year.
Indonesia
At year-end 2017, ExxonMobil had 0.1 million net acres onshore. In 2017, ExxonMobil relinquished approximately 0.4 million net
acres offshore.
Iraq
At year-end 2017, ExxonMobil’s onshore acreage was 0.1 million net acres. A total of 4.5 net development wells were completed
at the West Qurna Phase I oil field during the year. Oil field rehabilitation activities continued during 2017 and across the life of
this project will include drilling of new wells, working over of existing wells, and optimization and debottlenecking of existing
facilities. In the Kurdistan Region of Iraq, ExxonMobil continued exploration activities.
Kazakhstan
ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2017. A total of 4.3 net
development wells were completed during 2017. Development activities continued on the Tengiz Expansion project.
Malaysia
ExxonMobil’s interests in production sharing contracts covered 2.5 million net acres offshore at year-end 2017. During the year, a
total of 1.5 net development wells were completed. ExxonMobil acquired deepwater acreage offshore Sabah.
Qatar
Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2017.
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 2017.
Republic of Yemen
ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2017.
Russia
ExxonMobil’s net acreage holdings in Sakhalin at year-end 2017 were 85 thousand acres, all offshore. A total of 2.1 net exploration
and development wells were completed. The Odoptu Stage 2 project started up in 2017.
At year-end 2017, ExxonMobil’s net acreage in the Rosneft joint venture agreements for the Kara, Laptev, Chukchi and Black Seas
was 63.6 million acres, all offshore. ExxonMobil and Rosneft formed a joint venture to evaluate the development of tight-oil
reserves in western Siberia in 2013. Refer to the relevant portion of “Note 7: Equity Company Information” of the Financial Section
of this report for additional information on the Corporation’s participation in Rosneft joint venture activities.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2017.
United Arab Emirates
ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2017. A total
of 5.3 net development wells were completed. During 2017, development activities continued on the Upper Zakum 750 project,
and agreements were signed for the Upper Zakum 1MBD (million barrels per day) project, including a 10-year extension to 2051
for the Upper Zakum concession.
16
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s year-end 2017 acreage holdings totaled 2.0 million net offshore acres. The Gas Conditioning Plant at Longford
started up in 2017.
The third train of the co-venturer-operated Gorgon Jansz liquefied natural gas (LNG) project started up in 2017. The project consists
of a subsea infrastructure for offshore production and transportation of the gas, a 15.6 million tonnes per year LNG facility and a
280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.
Papua New Guinea
A total of 10.1 million net acres were held by ExxonMobil at year-end 2017, of which 5.4 million net acres were offshore. A total
of 0.7 net exploration and development wells were completed during the year. The Papua New Guinea (PNG) LNG integrated
development includes gas production and processing facilities in the southern PNG Highlands, onshore and offshore pipelines, and
a 6.9 million tonnes per year LNG facility near Port Moresby. In 2017, ExxonMobil acquired InterOil Corporation (IOC), an
exploration and production business focused on Papua New Guinea.
WORLDWIDE EXPLORATION
At year-end 2017, 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 30.1 million net acres were held at year-end 2017 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 2018 through 2020. 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 2017 Year-End 2016
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net
Gross and Net Productive Wells
Consolidated Subsidiaries
United States 20,679 8,366 27,700 15,979 20,470 8,037 32,949 19,873
Canada/Other Americas 4,877 4,618 4,273 1,646 5,024 4,767 4,362 1,668
Europe 1,016 267 664 268 1,130 323 641 253
Africa 1,222 474 15 6 1,268 494 17 7
Asia 900 299 139 82 882 299 140 82
Australia/Oceania 588 129 73 30 588 128 53 23
Total Consolidated Subsidiaries 29,282 14,153 32,864 18,011 29,362 14,048 38,162 21,906
Equity Companies
United States 13,796 5,247 4,227 491 13,957 5,315 4,257 491
Europe 59 21 617 195 56 19 586 186
Asia 144 36 125 30 131 33 125 30
Total Equity Companies 13,999 5,304 4,969 716 14,144 5,367 4,968 707
Total gross and net productive wells 43,281 19,457 37,833 18,727 43,506 19,415 43,130 22,613
There were 30,263 gross and 25,827 net operated wells at year-end 2017 and 35,047 gross and 29,375 net operated wells at year-
end 2016. The number of wells with multiple completions was 1,366 gross in 2017 and 1,209 gross in 2016.
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B. Gross and Net Developed Acreage
Year-End 2017 Year-End 2016
Gross Net Gross Net
(thousands of acres)
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States 14,836 9,026 14,678 8,958
Canada/Other Americas (1) 3,604 2,328 3,374 2,146
Europe 2,970 1,335 3,215 1,446
Africa 2,492 866 2,492 866
Asia 1,983 586 1,934 562
Australia/Oceania 3,262 1,068 3,020 1,005
Total Consolidated Subsidiaries 29,147 15,209 28,713 14,983
Equity Companies
United States 930 208 929 209
Europe 4,170 1,317 4,191 1,321
Asia 628 155 628 155
Total Equity Companies 5,728 1,680 5,748 1,685
Total gross and net developed acreage 34,875 16,889 34,461 16,668
(1) Includes developed acreage in Other Americas of 375 gross and 244 net thousands of acres for 2017 and 213 gross and 109
net thousands of acres for 2016.
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 2017 Year-End 2016
Gross Net Gross Net
(thousands of acres)
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States 7,506 3,489 7,854 3,637
Canada/Other Americas (1) 29,495 13,410 24,054 10,569
Europe 7,576 3,622 7,218 3,368
Africa 37,699 26,705 9,496 4,979
Asia 5,802 2,680 2,436 865
Australia/Oceania 15,976 11,125 8,054 5,497
Total Consolidated Subsidiaries 104,054 61,031 59,112 28,915
Equity Companies
United States 207 77 223 81
Europe 100 25 100 25
Africa 596 149 – –
Asia 191,147 63,633 191,147 63,633
Total Equity Companies 192,050 63,884 191,470 63,739
Total gross and net undeveloped acreage 296,104 124,915 250,582 92,654
(1) Includes undeveloped acreage in Other Americas of 18,625 gross and 8,053 net thousands of acres for 2017 and 13,106 gross
and 5,146 net thousands of acres for 2016.
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.
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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.
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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 signed in 2015; the initial exploration period is five years for oil and gas,
with multi-year extensions available at the discretion of the Ministry and limited relinquishments in the absence of commercial
discoveries. The production period for crude oil ranges from 25 to 30 years, while the production period for natural gas ranges from
25 to 50 years.
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 December 2017. Terms for Area 4 are governed by the Exploration and Production Concession Contract (EPCC) for
Area 4 Offshore of the Rovuma Block dated December 20, 2006 and Decree Law 2/2014. The EPCC expires 30 years after the
approval of a plan of development for a given discovery area.
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.
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.
21
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 is 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.
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.
22
Republic of Yemen
The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which
was made in June 1995. Due to force majeure events, the development period has been extended beyond its original expiration date,
with the possibility of further extensions due to ongoing force majeure events.
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.
Exploration and production activities in the Kara, Laptev, Chukchi and Black Seas are governed by joint venture agreements
concluded with Rosneft in 2013 and 2014 that cover certain of Rosneft’s offshore licenses. The Kara Sea licenses covered by the
joint venture agreements concluded in 2013 extend through 2040 and include exploration periods through 2020 and 2022.
Additional licenses in the Kara, Laptev and Chukchi Seas covered by the joint venture agreements concluded in 2014 extend through
2043 and include an exploration period through 2023. The Kara, Laptev and Chukchi Sea licenses require development plan
submission within eight to eleven years from a discovery and development activities within five years of plan approval. The Black
Sea exploration license extends through 2020, and a discovery is the basis for obtaining a license for production. Refer to the
relevant portion of “Note 7: Equity Company Information” of the Financial Section of this report for additional information on the
Corporation’s participation in Rosneft joint venture activities.
Thailand
The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a ten-year extension at terms
generally prevalent at the time. 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 effective
as of January 2006, for a term expiring March 2026. In 2013 the governing agreements were extended to 2041 and in 2017 they
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.
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Information with regard to the Downstream segment follows:
ExxonMobil’s Downstream segment manufactures and sells petroleum products. The refining and supply operations encompass a
global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants
and other products and feedstocks to our customers around the world.
Refining Capacity At Year-End 2017 (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 366 100
Total United States 1,726
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 239 82.9
Karlsruhe Germany 78 25
Augusta Italy 198 100
Trecate Italy 132 74.8
Rotterdam Netherlands 192 100
Slagen Norway 116 100
Fawley United Kingdom 262 100
Total Europe 1,657
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 4,918
(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 cost company refining capacity 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 2017
United States
Owned/leased –
Distributors/resellers 10,573
Total United States 10,573
Canada
Owned/leased –
Distributors/resellers 1,829
Total Canada 1,829
Europe
Owned/leased 1,843
Distributors/resellers 3,975
Total Europe 5,818
Asia Pacific
Owned/leased 598
Distributors/resellers 946
Total Asia Pacific 1,544
Latin America
Owned/leased 5
Distributors/resellers 785
Total Latin America 790
Middle East/Africa
Owned/leased 226
Distributors/resellers 182
Total Middle East/Africa 408
Worldwide
Owned/leased 2,672
Distributors/resellers 18,290
Total Worldwide 20,962
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 2017 (1)(2)
ExxonMobil
Ethylene Polyethylene Polypropylene Paraxylene Interest %
North America
Baton Rouge Louisiana 1.1 1.3 0.4 – 100
Baytown Texas 2.3 – 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 4.6 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 9.2 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
As reported in the Corporation’s Form 10-Q for the second quarter of 2017, on June 20, 2017, the United States Department of
Justice (DOJ) and the United States Environmental Protection Agency (EPA) notified XTO Energy Inc. (XTO) concerning alleged
violations of the Clean Air Act and the Fort Berthold Indian Reservation Federal Implementation Plan regarding the alleged failure
of vapor control systems to properly route tank vapors to control devices at well pads and tank farms on the Fort Berthold Indian
Reservation. In January 2018, XTO, the DOJ and the EPA agreed to the terms of a Consent Decree concerning those alleged
violations. XTO has agreed to pay a penalty of $320,000, install automatic tank gauging on 30 well sites, and monitor and report
emissions for three years. Following signature by EPA and the DOJ, the Consent Decree is subject to a 30-day public comment
period and approval by the United States Federal District Court for the District of North Dakota – Western Division, in Bismarck,
North Dakota, which is expected in March 2018.
As reported in the Corporation’s Form 10-Q for the second quarter of 2017, in late April 2017, the State of North Dakota Department
of Health (NDDOH) and the North Dakota State Office of the Attorney General notified XTO of their interest in settling alleged
violations of the North Dakota Century Code and implementing regulations regarding the alleged failure of vapor control systems
to properly route tank vapors to control devices at well pads and tank farms outside the Fort Berthold Indian Reservation. On
February 1, 2018, the South Central Judicial District Court in Bismarck, North Dakota, approved a Consent Decree between XTO
and NDDOH concerning those alleged violations. Under the Consent Decree, XTO will pay a civil penalty of up to $665,000, but
that amount may be reduced if specified corrective actions are achieved by deadlines set forth in the Consent Decree. Assuming
these deadlines are met, XTO anticipates that it will pay a penalty of approximately $440,000 in the fourth quarter of 2018. XTO
will monitor and report compliance with the terms of the Consent Decree for a period of two years.
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 28, 2018)
Darren W. Woods Chairman of the Board
Held current title since: January 1, 2017 Age: 53
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 still holds as of this
filing date.
Mark W. Albers Senior Vice President
Held current title since: April 1, 2007 Age: 61
Mr. Mark W. Albers became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as
of this filing date.
Neil A. Chapman Senior Vice President
Held current title since: January 1, 2018 Age: 55
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 still
holds as of this filing date.
Michael J. Dolan Senior Vice President
Held current title since: April 1, 2008 Age: 64
Mr. Michael J. Dolan became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as
of this filing date.
Andrew P. Swiger Senior Vice President
Held current title since: April 1, 2009 Age: 61
Mr. Andrew P. Swiger became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds
as of this filing date.
Jack P. Williams, Jr. Senior Vice President
Held current title since: June 1, 2014 Age: 54
Mr. Jack P. Williams, Jr. was President of XTO Energy Inc. June 25, 2010 – May 31, 2013. He was Executive Vice President
of ExxonMobil Production Company June 1, 2013 – June 30, 2014. He became Senior Vice President of Exxon Mobil
Corporation on June 1, 2014, a position he still holds as of this filing date.
Bradley W. Corson Vice President
Held current title since: March 1, 2015 Age: 56
Mr. Bradley W. Corson was Regional Vice President, Europe/Caspian for ExxonMobil Production Company May 1, 2009 –
April 30, 2014. He was Vice President, ExxonMobil Upstream Ventures May 1, 2014 – February 28, 2015. He became
President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation on March 1, 2015, positions he
still holds as of this filing date.
28
Neil W. Duffin Vice President
Held current title since: January 1, 2017 Age: 61
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 still holds as of this filing date.
Randall M. Ebner Vice President and General Counsel
Held current title since: November 1, 2016 Age: 62
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 still holds as of
this filing date.
Robert S. Franklin Vice President
Held current title since: May 1, 2009 Age: 60
Mr. Robert S. Franklin was President of ExxonMobil Upstream Ventures and Vice President of Exxon Mobil Corporation
May 1, 2009 – February 28, 2013. He became President of ExxonMobil Gas & Power Marketing Company and Vice President
of Exxon Mobil Corporation on March 1, 2013, positions he holds as of February 28, 2018.
Stephen M. Greenlee Vice President
Held current title since: September 1, 2010 Age: 60
Mr. Stephen M. Greenlee became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil
Corporation on September 1, 2010, positions he still holds as of this filing date.
Liam M. Mallon President, ExxonMobil Development Company
Held current title since: January 1, 2017 Age: 55
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 still holds as of this filing date.
Bryan W. Milton Vice President
Held current title since: August 1, 2016 Age: 53
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 still holds 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: 59
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 still holds as of this filing date.
David S. Rosenthal Vice President and Controller
Held current title since: October 1, 2008 (Vice President)
September 1, 2014 (Controller)
Age: 61
Mr. David S. Rosenthal was Vice President – Investor Relations and Secretary of Exxon Mobil Corporation October 1, 2008 –
August 31, 2014. He became Vice President and Controller of Exxon Mobil Corporation on September 1, 2014, positions he
still holds as of this filing date.
29
Robert N. Schleckser Vice President and Treasurer
Held current title since: May 1, 2011 Age: 61
Mr. Robert N. Schleckser became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, positions he still
holds as of this filing date.
James M. Spellings, Jr. Vice President and General Tax Counsel
Held current title since: March 1, 2010 Age: 56
Mr. James M. Spellings, Jr. became Vice President and General Tax Counsel of Exxon Mobil Corporation on March 1, 2010,
positions he still holds as of this filing date.
John R. Verity Vice President
Held current title since: January 1, 2018 Age: 59
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 still holds
as of this filing date.
Theodore J. Wojnar, Jr. Vice President – Corporate Strategic Planning
Held current title since: August 1, 2017 Age: 58
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 still
holds as of this filing date.
Jeffrey J. Woodbury Vice President – Investor Relations and Secretary
Held current title since: July 1, 2011 (Vice President)
September 1, 2014 (Secretary)
Age: 57
Mr. Jeffrey J. Woodbury was Vice President, Safety, Security, Health and Environment of Exxon Mobil Corporation
July 1, 2011 – August 31, 2014. He became Vice President – Investor Relations and Secretary of Exxon Mobil Corporation on
September 1, 2014, positions he still holds as of this filing date.
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each
such officer serving until a successor has been elected and qualified.
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, 2017
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 2017 – –
November 2017 – –
December 2017 – –
Total – – (See Note 1)
During the fourth quarter, the Corporation did not purchase any shares of its common stock for the treasury.
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,
2017 2016 2015 2014 2013
(millions of dollars, except per share amounts)
Sales and other operating revenue (1) 237,162 200,628 239,854 367,647 393,039
Net income attributable to ExxonMobil 19,710 7,840 16,150 32,520 32,580
Earnings per common share 4.63 1.88 3.85 7.60 7.37
Earnings per common share – assuming dilution 4.63 1.88 3.85 7.60 7.37
Cash dividends per common share 3.06 2.98 2.88 2.70 2.46
Total assets 348,691 330,314 336,758 349,493 346,808
Long-term debt 24,406 28,932 19,925 11,653 6,891
(1) Effective December 31, 2017, the Corporation revised its accounting policy election related to sales-based taxes. See Note 2:
Accounting Changes of the Financial Section of this report. As a result, Sales and other operating revenue excludes previously
reported sales-based taxes of $17,980 million in 2016, $19,634 million in 2015, $26,458 million in 2014 and $27,797 million
in 2013.
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.
31
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.
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 28, 2018, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and
continuing through “Note 20: Acquisitions”;
“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, 2017.
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, 2017.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s
internal control over financial reporting as of December 31, 2017, 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 2018 annual meeting of
shareholders (the “2018 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 2018 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 2018 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 37,374,885 (1) – 89,100,173 (2)(3)
Equity compensation plans not approved by security holders – – –
Total 37,374,885 – 89,100,173
(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 88,595,473
shares available for award under the 2003 Incentive Program and 504,700 shares available for award under the 2004
Non-Employee Director Restricted Stock Plan.
(3) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing
resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first
elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on
the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common
stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board
early.
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 2018 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 2018 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 35
Financial Information 36
Frequently Used Terms 37
Quarterly Information 39
Management’s Discussion and Analysis of Financial Condition
and Results of Operations
Functional Earnings 40
Forward-Looking Statements 40
Overview 40
Business Environment and Risk Assessment 41
Review of 2017 and 2016 Results 44
Liquidity and Capital Resources 47
Capital and Exploration Expenditures 51
Taxes 52
Environmental Matters 53
Market Risks, Inflation and Other Uncertainties 53
Recently Issued Accounting Standards 55
Critical Accounting Estimates 55
Management’s Report on Internal Control Over Financial Reporting 60
Report of Independent Registered Public Accounting Firm 61
Consolidated Financial Statements
Statement of Income 63
Statement of Comprehensive Income 64
Balance Sheet 65
Statement of Cash Flows 66
Statement of Changes in Equity 67
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies 68
2. Accounting Changes 72
3. Miscellaneous Financial Information 73
4. Other Comprehensive Income Information 74
5. Cash Flow Information 75
6. Additional Working Capital Information 75
7. Equity Company Information 76
8. Investments, Advances and Long-Term Receivables 78
9. Property, Plant and Equipment and Asset Retirement Obligations 78
10. Accounting for Suspended Exploratory Well Costs 80
11. Leased Facilities 82
12. Earnings Per Share 83
13. Financial Instruments and Derivatives 83
14. Long-Term Debt 84
15. Incentive Program 85
16. Litigation and Other Contingencies 86
17. Pension and Other Postretirement Benefits 88
18. Disclosures about Segments and Related Information 96
19. Income and Other Taxes 99
20. Acquisitions 103
Supplemental Information on Oil and Gas Exploration and Production Activities 104
Operating Information 119
BUSINESS PROFILE
35
Return on Capital and
Earnings After Average Capital Average Capital Exploration
Income Taxes Employed Employed Expenditures
Financial 2017 2016 2017 2016 2017 2016 2017 2016
(millions of dollars) (percent) (millions of dollars)
Upstream
United States 6,622 (4,151) 64,896 62,114 10.2 (6.7) 3,716 3,518
Non-U.S. 6,733 4,347 109,778 107,941 6.1 4.0 12,979 11,024
Total 13,355 196 174,674 170,055 7.6 0.1 16,695 14,542
Downstream
United States 1,948 1,094 7,936 7,573 24.5 14.4 823 839
Non-U.S. 3,649 3,107 14,578 14,231 25.0 21.8 1,701 1,623
Total 5,597 4,201 22,514 21,804 24.9 19.3 2,524 2,462
Chemical
United States 2,190 1,876 10,672 9,018 20.5 20.8 1,583 1,553
Non-U.S. 2,328 2,739 16,844 15,826 13.8 17.3 2,188 654
Total 4,518 4,615 27,516 24,844 16.4 18.6 3,771 2,207
Corporate and financing (3,760) (1,172) (2,073) (4,477) – – 90 93
Total 19,710 7,840 222,631 212,226 9.0 3.9 23,080 19,304
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Operating 2017 2016 2017 2016
(thousands of barrels daily) (thousands of barrels daily)
Net liquids production Refinery throughput
United States 514 494 United States 1,508 1,591
Non-U.S. 1,769 1,871 Non-U.S. 2,783 2,678
Total 2,283 2,365 Total 4,291 4,269
(millions of cubic feet daily) (thousands of barrels daily)
Natural gas production available for sale Petroleum product sales (2)
United States 2,936 3,078 United States 2,190 2,250
Non-U.S. 7,275 7,049 Non-U.S. 3,340 3,232
Total 10,211 10,127 Total 5,530 5,482
(thousands of oil-equivalent barrels daily) (thousands of metric tons)
Oil-equivalent production (1) 3,985 4,053 Chemical prime product sales (2) (3)
United States 9,307 9,576
Non-U.S. 16,113 15,349
Total 25,420 24,925
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same
counterparty.
(3) Prime product sales are total product sales including ExxonMobil’s share of equity company volumes and finished-product
transfers to the Downstream.
FINANCIAL INFORMATION
36
2017 2016 2015 2014 2013
(millions of dollars, except per share amounts)
Sales and other operating revenue (1) 237,162 200,628 239,854 367,647 393,039
Earnings
Upstream 13,355 196 7,101 27,548 26,841
Downstream 5,597 4,201 6,557 3,045 3,449
Chemical 4,518 4,615 4,418 4,315 3,828
Corporate and financing (3,760) (1,172) (1,926) (2,388) (1,538)
Net income attributable to ExxonMobil 19,710 7,840 16,150 32,520 32,580
Earnings per common share 4.63 1.88 3.85 7.60 7.37
Earnings per common share – assuming dilution 4.63 1.88 3.85 7.60 7.37
Cash dividends per common share 3.06 2.98 2.88 2.70 2.46
Earnings to average ExxonMobil share of equity (percent) 11.1 4.6 9.4 18.7 19.2
Working capital (10,637) (6,222) (11,353) (11,723) (12,416)
Ratio of current assets to current liabilities (times) 0.82 0.87 0.79 0.82 0.83
Additions to property, plant and equipment 24,901 16,100 27,475 34,256 37,741
Property, plant and equipment, less allowances 252,630 244,224 251,605 252,668 243,650
Total assets 348,691 330,314 336,758 349,493 346,808
Exploration expenses, including dry holes 1,790 1,467 1,523 1,669 1,976
Research and development costs 1,063 1,058 1,008 971 1,044
Long-term debt 24,406 28,932 19,925 11,653 6,891
Total debt 42,336 42,762 38,687 29,121 22,699
Fixed-charge coverage ratio (times) 13.2 5.7 17.6 46.9 55.7
Debt to capital (percent) 17.9 19.7 18.0 13.9 11.2
Net debt to capital (percent) (2) 16.8 18.4 16.5 11.9 9.1
ExxonMobil share of equity at year-end 187,688 167,325 170,811 174,399 174,003
ExxonMobil share of equity per common share 44.28 40.34 41.10 41.51 40.14
Weighted average number of common shares
outstanding (millions) 4,256 4,177 4,196 4,282 4,419
Number of regular employees at year-end (thousands) (3) 69.6 71.1 73.5 75.3 75.0
CORS employees not included above (thousands) (4) 1.6 1.6 2.1 8.4 9.8
(1) Effective December 31, 2017, the Corporation revised its accounting policy election related to sales-based taxes. See Note 2
to the financial statements, Accounting Changes. As a result, Sales and other operating revenue excludes previously reported
sales-based taxes of $17,980 million for 2016, $19,634 million for 2015, $26,458 million for 2014 and $27,797 million for
2013.
(2) Debt net of cash, excluding restricted cash.
(3) Regular employees are defined as active executive, management, professional, technical and wage employees who work full
time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.
(4) CORS employees are employees of company-operated retail sites.
FREQUENTLY USED TERMS
37
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 2017 2016 2015
(millions of dollars)
Net cash provided by operating activities 30,066 22,082 30,344
Proceeds associated with sales of subsidiaries, property, plant and equipment,
and sales and returns of investments 3,103 4,275 2,389
Cash flow from operations and asset sales 33,169 26,357 32,733
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 2017 2016 2015
(millions of dollars)
Business uses: asset and liability perspective
Total assets 348,691 330,314 336,758
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable (39,841) (33,808) (35,214)
Total long-term liabilities excluding long-term debt (72,014) (79,914) (86,047)
Noncontrolling interests share of assets and liabilities (8,298) (8,031) (8,286)
Add ExxonMobil share of debt-financed equity company net assets 3,929 4,233 4,447
Total capital employed 232,467 212,794 211,658
Total corporate sources: debt and equity perspective
Notes and loans payable 17,930 13,830 18,762
Long-term debt 24,406 28,932 19,925
ExxonMobil share of equity 187,688 167,325 170,811
Less noncontrolling interests share of total debt (1,486) (1,526) (2,287)
Add ExxonMobil share of equity company debt 3,929 4,233 4,447
Total capital employed 232,467 212,794 211,658
FREQUENTLY USED TERMS
38
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 2017 2016 2015
(millions of dollars)
Net income attributable to ExxonMobil 19,710 7,840 16,150
Financing costs (after tax)
Gross third-party debt (709) (683) (362)
ExxonMobil share of equity companies (204) (225) (170)
All other financing costs – net 515 423 88
Total financing costs (398) (485) (444)
Earnings excluding financing costs 20,108 8,325 16,594
Average capital employed 222,631 212,226 208,755
Return on average capital employed – corporate total 9.0% 3.9% 7.9%
QUARTERLY INFORMATION
39
2017 2016
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, 2,333 2,269 2,280 2,251 2,283 2,538 2,330 2,211 2,384 2,365
synthetic oil and bitumen
Refinery throughput 4,324 4,345 4,287 4,207 4,291 4,185 4,152 4,365 4,371 4,269
Petroleum product sales (1) 5,395 5,558 5,542 5,624 5,530 5,334 5,500 5,585 5,506 5,482
Natural gas production (millions of cubic feet daily)
available for sale 10,908 9,920 9,585 10,441 10,211 10,724 9,762 9,601 10,424 10,127
(thousands of oil-equivalent barrels daily)
Oil-equivalent production (2) 4,151 3,922 3,878 3,991 3,985 4,325 3,957 3,811 4,121 4,053
(thousands of metric tons)
Chemical prime product sales (1) 6,072 6,120 6,446 6,782 25,420 6,173 6,310 6,133 6,309 24,925
Summarized financial data
Sales and other operating (millions of dollars)
revenue (3) 56,474 56,026 59,350 65,312 237,162 43,032 51,714 52,123 53,759 200,628
Gross profit (4) 13,751 12,773 14,704 13,696 54,924 9,999 11,687 11,774 8,762 42,222
Net income attributable to
ExxonMobil (5) 4,010 3,350 3,970 8,380 19,710 1,810 1,700 2,650 1,680 7,840
Per share data (dollars per share)
Earnings per common share (6) 0.95 0.78 0.93 1.97 4.63 0.43 0.41 0.63 0.41 1.88
Earnings per common share
– assuming dilution (6) 0.95 0.78 0.93 1.97 4.63 0.43 0.41 0.63 0.41 1.88
Dividends per common share 0.75 0.77 0.77 0.77 3.06 0.73 0.75 0.75 0.75 2.98
Common stock prices
High 91.34 83.69 82.49 84.36 91.34 85.10 93.83 95.55 93.22 95.55
Low 80.31 79.26 76.05 80.01 76.05 71.55 81.99 82.29 82.76 71.55
(1) Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same counterparty.
(2) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(3) Effective December 31, 2017, the Corporation revised its accounting policy election related to sales-based taxes. See Note 2 to the financial
statements, Accounting Changes. As a result, Sales and other operating revenue excludes previously reported sales-based taxes of $4,616
million for first quarter 2017, $4,799 million for second quarter 2017, $5,065 million for third quarter 2017, $4,073 million for first quarter
2016, $4,646 million for second quarter 2016, $4,644 million for third quarter 2016, $4,617 million for fourth quarter 2016, and $17,980
million for the year 2016.
(4) Gross profit equals sales and other operating revenue less estimated costs associated with products sold. Effective December 31, 2017, the
Corporation revised its accounting policy election related to sales-based taxes, which reduced previously reported gross profit by the
amounts shown in note (3) above. See Note 2 to the financial statements, Accounting Changes.
(5) Fourth quarter 2017 included a U.S. tax reform impact of $5,942 million and an impairment charge of $1,294 million. Fourth quarter 2016
included an impairment charge of $2,135 million.
(6) Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year.
The intraday price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where
ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York
Stock Exchange, although the stock is traded on other exchanges in and outside the United States.
There were 386,892 registered shareholders of ExxonMobil common stock at December 31, 2017. At January 31, 2018, the
registered shareholders of ExxonMobil common stock numbered 384,745.
On January 31, 2018, the Corporation declared a $0.77 dividend per common share, payable March 9, 2018.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
40
FUNCTIONAL EARNINGS 2017 2016 2015
(millions of dollars, except per share amounts)
Earnings (U.S. GAAP)
Upstream
United States 6,622 (4,151) (1,079)
Non-U.S. 6,733 4,347 8,180
Downstream
United States 1,948 1,094 1,901
Non-U.S. 3,649 3,107 4,656
Chemical
United States 2,190 1,876 2,386
Non-U.S. 2,328 2,739 2,032
Corporate and financing (3,760) (1,172) (1,926)
Net income attributable to ExxonMobil (U.S. GAAP) 19,710 7,840 16,150
Earnings per common share 4.63 1.88 3.85
Earnings per common share – assuming dilution 4.63 1.88 3.85
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 mix; government policies relating
to climate change; 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, and other factors discussed herein and in Item 1A. Risk Factors.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning
as in any government payment transparency reports.
OVERVIEW
The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and
related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil
Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the
extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model
involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in
support of the underlying physical movement of goods.
ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned
to participate in substantial investments to develop new energy supplies. The company’s integrated business model, with significant
investments in Upstream, Downstream and Chemical segments, reduces the Corporation’s risk from changes in commodity prices.
While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment decisions
are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment
opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and
capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes
are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined
products, and chemical products are based on corporate plan assumptions developed annually by major region and are utilized for
investment evaluation purposes. Major investment opportunities are evaluated over a range of economic scenarios. Once major
investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated
into future projects.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
41
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
The basis for the Long-Term Business Outlook is the Corporation’s annual 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 to grow to approximately
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. As economies and populations grow, and as living standards
improve for billions of people, the need for energy will continue to rise. Even with significant efficiency gains, global energy
demand is projected to rise by about 25 percent from 2016 to 2040. This demand increase is expected to be concentrated in
developing countries (i.e., those that are not member nations of the Organisation for Economic Co-operation and Development).
As expanding prosperity drives global energy demand higher, increasing use of energy-efficient 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 transportation, power generation, industrial applications, and residential and commercial needs.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 30 percent from
2016 to 2040. The growth in transportation energy demand is likely to account for approximately 60 percent of the growth in liquid
fuels demand worldwide over this period, even as liquids demand for light-duty vehicles is relatively flat to 2040, reflecting the
impact of better fleet fuel economy and significant growth in electric cars over the period. Nearly all the world’s transportation
fleets are likely to continue to run on liquid fuels, which are abundant, widely available, easy to transport, and provide a large
quantity of energy in small volumes.
Demand for electricity around the world is likely to increase approximately 60 percent from 2016 to 2040, with developing countries
accounting 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. Meeting the expected growth in power demand will require
a diverse set 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.
Renewables in total, led by wind and solar, will account for about half of the increase in electricity supplies worldwide over the
period to 2040, reaching nearly 35 percent of global electricity supplies by 2040. Natural gas and nuclear will also gain share 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.
Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of
distribution, 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. Much of this
demand today is met by crude production from traditional conventional sources; these supplies will remain important as 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, access to resources and timely investments will remain critical to meeting
global needs with reliable, affordable supplies.
Natural gas is a versatile fuel, suitable for a wide variety of applications, and it is expected to 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. Helping meet these
needs will be significant growth in supplies of unconventional gas – the natural gas found in shale and other rock formations that
was once considered uneconomic to produce. In total, about 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 supply,
meeting about two-thirds of global demand in 2040. Worldwide liquefied natural gas (LNG) trade will expand significantly, meeting
about one-third of the increase in demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy
with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that
position to natural gas in the 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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
42
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 be about 5 percent of world energy.
The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also
from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply
these resources will be significant. According to the International Energy Agency’s World Energy Outlook 2017, the investment
required to meet oil and natural gas supply requirements worldwide over the period 2017-2040 will be about $21 trillion (New
Policies Scenario, measured in 2016 dollars) or approximately $860 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, by using various assumptions and tools including application of a proxy cost of carbon to estimate potential impacts
on consumer demands. 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 maintain a diverse portfolio of exploration and development opportunities, which enables the Corporation
to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream
business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies
include capturing material and accretive opportunities to continually high-grade the resource portfolio, 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. Oil equivalent production from North America is expected
to increase over the next several years based on current investment plans, contributing over a third of total production. Further, the
proportion of our global production from resource types utilizing specialized technologies such as unconventional drilling and
production systems, LNG, deepwater, and arctic, is a majority of production and is expected to grow over the next few years. We
do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from
which volumes will be produced, will have a material impact on the nature and the extent of the risks disclosed in Item 1A. Risk
Factors, or result in a material change in our level of unit operating expenses.
The Corporation anticipates several projects will come online over the next few years providing additional production capacity.
However, actual volumes will vary from year to year due to the timing of individual project start-ups; operational outages; reservoir
performance; performance of enhanced oil recovery projects; regulatory changes; the impact of fiscal and commercial terms; asset
sales; weather events; price effects on production sharing contracts; changes in the amount and timing of capital investments that
may vary depending on the oil and gas price environment; and other factors described in Item 1A. Risk Factors.
The upstream industry environment continued to recover in 2017 as crude oil prices increased in response to tighter supply and
higher demand; gas prices also improved with increasing demand, particularly in Asia. 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 and levels of prosperity. On the
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
43
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 2017, our Upstream business produced 4 million oil-equivalent barrels per day. During the year, we added over
200,000 oil-equivalent barrels per day of gross production capacity through project start-ups in Eastern Canada (Hebron) and at our
Sakhalin-1 operation in Russia (Odoptu Stage 2). We added 2.7 billion oil-equivalent barrels of proved reserves, reflecting a
183 percent replacement of 2017 production. We also made strategic acquisitions in Papua New Guinea, Mozambique, and U.S.
tight oil, and continued to have exploration success in Guyana.
Downstream
ExxonMobil’s Downstream is a large, diversified business with refining, logistics, and marketing complexes around the world. The
Corporation has a presence in mature markets in North America and Europe, as well as in the growing Asia Pacific region.
ExxonMobil’s fundamental Downstream business strategies 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 22 refineries, located in 14 countries, with distillation
capacity of 4.9 million barrels per day and lubricant basestock manufacturing capacity of 125 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 and Mobil 1.
Demand growth remained strong in 2017, and margins strengthened during the year drawing on previous high inventories,
particularly in North America due to Latin American demand and hurricane related refinery outages. North American refineries
also benefited from cost-competitive feedstock and energy supplies as the differential between Brent and WTI widened. Margins
in Europe and Asia strengthened versus 2016, with rising Asia demand and economic growth in Europe. In the near term, we see
variability in refining margins, with some regions seeing weaker margins as new capacity additions are expected to outpace growth
in global demand for our products, which can also be affected by global economic conditions and regulatory changes.
Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery
pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating
oil, diesel oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted
on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these
commodities are determined by the global marketplace and are influenced by many factors, including global and regional
supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal
demand, weather, and political climate.
ExxonMobil’s long-term outlook is that industry refining margins will remain subject to intense competition as new capacity
additions outpace the growth in global demand. ExxonMobil’s integration across the value chain, from refining to marketing,
enhances overall value in both fuels and lubricants businesses.
As described in more detail in Item 1A. Risk Factors, proposed carbon policy and other climate-related regulations in many
countries, as well as the continued growth in biofuels mandates, could have negative impacts on the Downstream business.
In the fuels marketing business, margins remained relatively flat in 2017. In 2017, ExxonMobil expanded its branded retail site
network and progressed the multi-year transition of the direct served (i.e., dealer, company-operated) retail network in portions of
Europe to a more capital-efficient Branded Wholesaler model. The company’s lubricants business continues to grow, leveraging
world-class brands and integration with industry-leading basestock refining capability. ExxonMobil remains a market leader in the
high-value synthetic lubricants sector, despite increasing competition.
The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have
been made over the past decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient
projects. At the end of 2017, construction was nearly complete on a new delayed coker unit at the refinery in Antwerp, Belgium, to
upgrade low-value bunker fuel into higher value diesel products. Construction also progressed on a proprietary hydrocracker at the
refinery in Rotterdam, Netherlands, to produce higher value ultra-low sulfur diesel and Group II basestocks. In addition, an
expansion in Singapore is underway to support demand growth for finished lubricants in key markets. Finally, ExxonMobil
announced plans to increase production of ultra-low sulfur fuels at the Beaumont, Texas, refinery by approximately 40,000 barrels
per day.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
44
Chemical
Worldwide petrochemical demand remained strong in 2017, led by growing demand from Asia Pacific manufacturers of industrial
and consumer products. North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both
low-cost feedstock and energy. Specialty product margins moderated in 2017 with capacity additions exceeding demand growth.
ExxonMobil sustained its competitive advantage through continued operational excellence, investment and cost discipline, a
balanced portfolio of products, and integration with refining and upstream operations, all underpinned by proprietary technology.
In 2017, we completed start-up of the polyethylene derivative lines in Mont Belvieu, Texas, and the adhesion hydrocarbon resin
plant in Singapore. Construction continued on major expansions at our Texas facilities, including a new world-scale ethane cracker
in Baytown and expansion of the polyethylene plant in Beaumont, to capitalize on low-cost feedstock and energy supplies in North
America and to meet rapidly growing demand for premium polymers. The company also continued construction on the specialty
elastomers plant expansion in Newport, Wales, with start-up anticipated in 2018. Construction of a new halobutyl rubber unit also
progressed in Singapore to further extend our specialty product capacity in Asia Pacific. In addition, the company completed the
acquisition of a petrochemical plant from Jurong Aromatics Corporation, to complement the existing petrochemical complex in
Singapore and meet growing demand for chemicals products in Asia Pacific.
REVIEW OF 2017 AND 2016 RESULTS
2017 2016 2015
(millions of dollars)
Earnings (U.S. GAAP)
Net income attributable to ExxonMobil (U.S. GAAP) 19,710 7,840 16,150
Upstream
2017 2016 2015
(millions of dollars)
Upstream
United States 6,622 (4,151) (1,079)
Non-U.S. 6,733 4,347 8,180
Total 13,355 196 7,101
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. 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. 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.
2016
Upstream earnings were $196 million in 2016 and included asset impairment charges of $2,163 million mainly relating to dry gas
operations with undeveloped acreage in the Rocky Mountains region of the U.S. Earnings were down $6,905 million from 2015.
Lower realizations decreased earnings by $5.3 billion. Favorable volume and mix effects increased earnings by $130 million. The
impairment charges reduced earnings by $2.2 billion. All other items increased earnings by $440 million, primarily due to lower
expenses partly offset by the absence of favorable tax items from the prior year. On an oil equivalent basis, production of 4.1 million
barrels per day was down slightly compared to 2015. Liquids production of 2.4 million barrels per day increased 20,000 barrels per
day with increased project volumes, mainly in Canada, Indonesia and Nigeria, partly offset by field decline, the impact from
Canadian wildfires, and downtime notably in Nigeria. Natural gas production of 10.1 billion cubic feet per day decreased
388 million cubic feet per day from 2015 as field decline, regulatory restrictions in the Netherlands and divestments were partly
offset by higher project volumes and work programs. U.S. Upstream earnings declined $3,072 million from 2015 to a loss of
$4,151 million, and included impairment charges of $2,163 million. Earnings outside the U.S. were $4,347 million, down
$3,833 million from the prior year.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
45
Upstream Additional Information
2017 2016
(thousands of barrels daily)
Volumes Reconciliation (Oil-equivalent production) (1)
Prior Year 4,053 4,097
Entitlements – Net Interest – 9
Entitlements – Price / Spend / Other (62) (23)
Quotas – –
Divestments (15) (34)
Growth / Other 9 4
Current Year 3,985 4,053
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
Listed below are descriptions of ExxonMobil’s volumes reconciliation factors which are provided to facilitate understanding of the
terms.
Entitlements – Net Interest are changes to ExxonMobil’s share of production volumes caused by non-operational changes to
volume-determining factors. These factors consist of net interest changes specified in Production Sharing Contracts (PSCs) which
typically occur when cumulative investment returns or production volumes achieve defined thresholds, changes in equity upon
achieving pay-out in partner investment carry situations, equity redeterminations as specified in venture agreements, or as a result
of the termination or expiry of a concession. Once a net interest change has occurred, it typically will not be reversed by subsequent
events, such as lower crude oil prices.
Entitlements – Price, Spend and Other are changes to ExxonMobil’s share of production volumes resulting from temporary changes
to non-operational volume-determining factors. These factors include changes in oil and gas prices or spending levels from one
period to another. According to the terms of contractual arrangements or government royalty regimes, price or spending variability
can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. For example, at higher prices, fewer barrels
are required for ExxonMobil to recover its costs. These effects generally vary from period to period with field spending patterns or
market prices for oil and natural gas. Such factors can also include other temporary changes in net interest as dictated by specific
provisions in production agreements.
Quotas are changes in ExxonMobil’s allowable production arising from production constraints imposed by countries which are
members of the Organization of the Petroleum Exporting Countries (OPEC). Volumes reported in this category would have been
readily producible in the absence of the quota.
Divestments are reductions in ExxonMobil’s production arising from commercial arrangements to fully or partially reduce equity
in a field or asset in exchange for financial or other economic consideration.
Growth and Other factors comprise all other operational and non-operational factors not covered by the above definitions that may
affect volumes attributable to ExxonMobil. Such factors include, but are not limited to, production enhancements from project and
work program activities, acquisitions including additions from asset exchanges, downtime, market demand, natural field decline,
and any fiscal or commercial terms that do not affect entitlements.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
46
Downstream
2017 2016 2015
(millions of dollars)
Downstream
United States 1,948 1,094 1,901
Non-U.S. 3,649 3,107 4,656
Total 5,597 4,201 6,557
2017
Downstream earnings of $5,597 million increased $1,396 million from 2016. Stronger refining and marketing margins increased
earnings by $1.5 billion, while 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 the current
year. Petroleum product sales of 5.5 million barrels per day were 48,000 barrels per day higher than 2016. Earnings from the U.S.
Downstream 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.
2016
Downstream earnings of $4,201 million decreased $2,356 million from 2015. Weaker refining and marketing margins decreased
earnings by $3.8 billion, while volume and mix effects increased earnings by $560 million. All other items increased earnings by
$920 million, mainly reflecting gains from divestments, notably in Canada. Petroleum product sales of 5.5 million barrels per day
were 272,000 barrels per day lower than 2015 mainly reflecting the divestment of refineries in California and Louisiana. U.S.
Downstream earnings were $1,094 million, a decrease of $807 million from 2015. Non-U.S. Downstream earnings were
$3,107 million, down $1,549 million from the prior year.
Chemical
2017 2016 2015
(millions of dollars)
Chemical
United States 2,190 1,876 2,386
Non-U.S. 2,328 2,739 2,032
Total 4,518 4,615 4,418
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. Prime product sales of 25.4 million metric tons were up 495,000 metric tons from 2016. 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.
2016
Chemical earnings of $4,615 million increased $197 million from 2015. Stronger margins increased earnings by $440 million.
Favorable volume and mix effects increased earnings by $100 million. All other items decreased earnings by $340 million,
primarily due to the absence of U.S. asset management gains. Prime product sales of 24.9 million metric tons were up
212,000 metric tons from 2015. U.S. Chemical earnings were $1,876 million, down $510 million from 2015 reflecting the absence
of asset management gains. Non-U.S. Chemical earnings of $2,739 million were $707 million higher than the prior year.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
47
Corporate and Financing
2017 2016 2015
(millions of dollars)
Corporate and financing (3,760) (1,172) (1,926)
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.
2016
Corporate and financing expenses of $1,172 million in 2016 were $754 million lower than 2015 mainly reflecting favorable
non-U.S. tax items.
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
2017 2016 2015
(millions of dollars)
Net cash provided by/(used in)
Operating activities 30,066 22,082 30,344
Investing activities (15,730) (12,403) (23,824)
Financing activities (15,130) (9,293) (7,037)
Effect of exchange rate changes 314 (434) (394)
Increase/(decrease) in cash and cash equivalents (480) (48) (911)
(December 31)
Total cash and cash equivalents 3,177 3,657 3,705
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.
Total cash and cash equivalents were $3.7 billion at the end of 2016, essentially in line with the prior year. The major sources of
funds in 2016 were net income including noncontrolling interests of $8.4 billion, the adjustment for the noncash provision of
$22.3 billion for depreciation and depletion, proceeds from asset sales of $4.3 billion, and a net debt increase of $4.3 billion. The
major uses of funds included spending for additions to property, plant and equipment of $16.2 billion, dividends to shareholders of
$12.5 billion, the adjustment for noncash deferred income tax credits of $4.4 billion, and a change in working capital, excluding
cash and debt, of $1.4 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, 2017, the
Corporation had unused committed short-term lines of credit of $5.4 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, 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
48
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 2017 were $23.1 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an
investment level of $24 billion in 2018.
Actual spending could vary depending on the progress of individual projects and property acquisitions. The Corporation has a large
and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical
risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and
diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact
on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.
Cash Flow from Operating Activities
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.
2016
Cash provided by operating activities totaled $22.1 billion in 2016, $8.3 billion lower than 2015. The major source of funds was
net income including noncontrolling interests of $8.4 billion, a decrease of $8.2 billion. The noncash provision for depreciation and
depletion was $22.3 billion, up $4.3 billion from the prior year. The adjustment for net gains on asset sales was $1.7 billion while
the adjustment for deferred income tax credits was $4.4 billion. Changes in operational working capital, excluding cash and debt,
decreased cash in 2016 by $1.4 billion.
Cash Flow from Investing Activities
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.
2016
Cash used in investing activities netted to $12.4 billion in 2016, $11.4 billion lower than 2015. Spending for property, plant and
equipment of $16.2 billion decreased $10.3 billion from 2015. Proceeds associated with sales of subsidiaries, property, plant and
equipment, and sales and returns of investments of $4.3 billion compared to $2.4 billion in 2015. Additional investments and
advances were $0.8 billion higher in 2016.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
49
Cash Flow from Financing Activities
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.
2016
Cash used in financing activities was $9.3 billion in 2016, $2.3 billion higher than 2015. Dividend payments on common shares
increased to $2.98 per share from $2.88 per share and totaled $12.5 billion. Total debt increased $4.1 billion to $42.8 billion at
year-end. The first quarter issuance of $12.0 billion in long-term debt was partly offset by repayments of $8.0 billion in commercial
paper and other short-term debt during the year.
ExxonMobil share of equity decreased $3.5 billion to $167.3 billion. The addition to equity for earnings was $7.8 billion. This was
offset by reductions for distributions to ExxonMobil shareholders of $12.5 billion, all in the form of dividends. Foreign exchange
translation effects of $0.3 billion for the stronger U.S. currency reduced equity, while a $1.6 billion change in the funded status of
the postretirement benefits reserves increased equity.
During 2016, Exxon Mobil Corporation acquired 12 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
were reduced from 4,156 million to 4,148 million at the end of 2016.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
50
Commitments
Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31,
2017. The table combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial
Statements.
Payments Due by Period
Note 2023
Reference 2019- 2021- and
Commitments Number 2018 2020 2022 Beyond Total
(millions of dollars)
Long-term debt (1) 14 – 5,662 4,384 14,360 24,406
– Due in one year (2) 6 4,766 – – – 4,766
Asset retirement obligations (3) 9 777 1,856 894 9,178 12,705
Pension and other postretirement obligations (4) 17 2,061 1,991 1,947 14,704 20,703
Operating leases (5) 11 936 1,166 667 1,521 4,290
Take-or-pay and unconditional purchase obligations (6) 3,389 5,973 4,870 12,259 26,491
Firm capital commitments (7) 5,743 2,338 828 737 9,646
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 $8.8 billion as of December 31, 2017, 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 $1,327 million.
(2) The amount due in one year is included in Notes and loans payable of $17,930 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
2018 and estimated benefit payments for unfunded plans in all years.
(5) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service
stations and other properties. Total includes $611 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 $26,491 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 $9.6 billion, including $1.9 billion in the U.S. Firm capital commitments for the non-U.S.
Upstream of $7.2 billion were primarily associated with projects in the United Arab Emirates, Africa, United Kingdom,
Guyana, Malaysia, Norway, Canada and Australia. The Corporation expects to fund the majority of these commitments with
internally generated funds, supplemented by short-term and long-term debt as required.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
51
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2017, 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, 2017, the Corporation’s unused short-term committed lines of credit totaled $5.4 billion (Note 6) and unused
long-term committed lines of credit totaled $0.2 billion (Note 14). The table below shows the Corporation’s fixed-charge coverage
and consolidated debt-to-capital ratios. The data demonstrates the Corporation’s creditworthiness.
2017 2016 2015
Fixed-charge coverage ratio (times) 13.2 5.7 17.6
Debt to capital (percent) 17.9 19.7 18.0
Net debt to capital (percent) 16.8 18.4 16.5
Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to
be a competitive advantage of strategic importance. The Corporation’s sound financial position gives it the opportunity to access
the world’s capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital
commitments in the pursuit of maximizing shareholder value.
Litigation and Other Contingencies
As discussed in Note 16, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a
number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the
ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s
operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already
included in reported financial information that would indicate a material change in future operating results or financial condition.
Refer to Note 16 for additional information on legal proceedings and other contingencies.
CAPITAL AND EXPLORATION EXPENDITURES
2017 2016
U.S. Non-U.S. Total U.S. Non-U.S. Total
(millions of dollars)
Upstream (1) 3,716 12,979 16,695 3,518 11,024 14,542
Downstream 823 1,701 2,524 839 1,623 2,462
Chemical 1,583 2,188 3,771 1,553 654 2,207
Other 90 – 90 93 – 93
Total 6,212 16,868 23,080 6,003 13,301 19,304
(1) Exploration expenses included.
Capital and exploration expenditures in 2017 were $23.1 billion, as the Corporation continued to pursue opportunities to find and
produce new supplies of oil and natural gas to meet global demand for energy. The Corporation anticipates an investment level of
$24 billion in 2018. Actual spending could vary depending on the progress of individual projects and property acquisitions.
Upstream spending of $16.7 billion in 2017 was up 15 percent from 2016. Investments in 2017 included acquisitions in Mozambique
and Brazil, U.S. onshore drilling activity 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 66 percent of total proved reserves at year-end 2017, and has been over
60 percent for the last ten years.
Capital investments in the Downstream totaled $2.5 billion in 2017, consistent with 2016, reflecting global refining project
spending. Chemical capital expenditures of $3.8 billion increased $1.6 billion from 2016 mainly resulting from the acquisition of a
large-scale aromatics plant in Singapore.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
52
TAXES
2017 2016 2015
(millions of dollars)
Income taxes (1,174) (406) 5,415
Effective income tax rate 5% 13% 34%
Total other taxes and duties 32,459 31,375 32,834
Total 31,285 30,969 38,249
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.
2016
Total taxes were $31.0 billion in 2016, a decrease of $7.2 billion from 2015. Income tax expense, both current and deferred, was a
credit of $0.4 billion, $5.8 billion lower than 2015, reflecting lower 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 13 percent compared to 34
percent in the prior year due primarily to a lower share of earnings in higher tax jurisdictions, favorable one-time items, and the
impact of the U.S. Upstream impairment charge. Total other taxes and duties of $31.4 billion in 2016 decreased $1.5 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 has included reasonable estimates of the income tax effects of the changes in tax law and tax rate. These include
amounts for the remeasurement of the deferred income tax balance from the reduction in the corporate tax rate from 35 to 21 percent
and the mandatory deemed repatriation of undistributed foreign earnings and profits. ExxonMobil’s significant historical
investments in the United States have created large deferred income tax liabilities. Remeasurement of these deferred income tax
liabilities from the 35 percent rate to 21 percent results in a one-time non-cash benefit to earnings. The Corporation has paid taxes
on earnings outside the United States at tax rates on average above the historical U.S. rate of 35 percent. As a result, the deemed
repatriation tax does not create a significant tax impact for ExxonMobil. The impact of tax law changes on the Corporation’s
financial statements could differ from its estimates due to further analysis of the new law, regulatory guidance, technical corrections
legislation, or guidance under U.S. GAAP. If significant changes occur, the Corporation will provide updated information in
connection with future regulatory filings.
The 21 percent corporate tax rate will reduce the tax cost of U.S. earnings from U.S. investments, although the savings may be
somewhat offset by other provisions that could raise the Corporation’s future tax liability. Within the normal course of business,
other provisions of the tax law that are effective in 2018 are not expected to have a material effect on operating results or financial
condition.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
53
ENVIRONMENTAL MATTERS
Environmental Expenditures
2017 2016
(millions of dollars)
Capital expenditures 1,321 1,436
Other expenditures 3,349 3,451
Total 4,670 4,887
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 2017
worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity
company expenditures, were $4.7 billion, of which $3.3 billion were included in expenses with the remainder in capital
expenditures. The total cost for such activities is expected to increase to approximately $5 billion in 2018 and 2019. 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 2017 for environmental liabilities were $302 million ($665 million in 2016) and the balance sheet
reflects accumulated liabilities of $872 million as of December 31, 2017, and $852 million as of December 31, 2016.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations (1) 2017 2016 2015
Crude oil and NGL ($ per barrel) 48.91 38.15 44.77
Natural gas ($ per thousand cubic feet) 3.04 2.25 2.95
(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 $425 million annual after-tax effect
on Upstream consolidated plus equity company earnings. 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. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of
individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude
and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators
of changes in the earnings experienced in any particular period.
In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than
absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw
materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and
regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
54
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 interest rates, currency rates and commodity
prices. In addition, the Corporation uses commodity-based contracts, including derivatives, to manage commodity price risk and
for trading purposes. 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
believes that there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as
a result of the derivatives described in Note 13. The Corporation 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.
Beginning several years ago, an extended period of increased demand for certain services and materials resulted in higher operating
and capital costs. Since then, multiple market changes, including lower oil prices and reduced upstream industry activity, have
contributed to lower prices for oilfield services and materials. 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
55
RECENTLY ISSUED ACCOUNTING STANDARDS
Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s standard, Revenue from Contracts
with Customers, 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 on the impact of
the new standard must be provided for 2018 results, if material. The standard is not expected to have a material impact on the
Corporation’s financial statements. The cumulative effect of adoption of the new standard is de minimis.
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. Companies can elect a modified approach for equity securities that
do not have a readily determinable fair value. The standard is not expected to have a material impact on the Corporation’s financial
statements.
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 the service cost component of net benefit costs to be reported in the same line of the income statement as other
compensation costs and the other components of net benefit costs (non-service costs) to be presented separately from the service
cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The Corporation
expects to add a new line “Non-service pension and postretirement benefit expense” to its Consolidated Statement of Income and
expects to include all of these costs in its Corporate and financing segment. This line would reflect the non-service costs that were
previously included in “Production and manufacturing expenses” and “Selling, general and administrative expenses”. The update
is not expected to have a material impact on the Corporation’s financial statements.
Effective January 1, 2019, ExxonMobil will adopt the Financial Accounting Standards Board’s standard, Leases. The standard
requires all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. The
Corporation is gathering and evaluating data and recently acquired a system to facilitate implementation. We are progressing an
assessment of the magnitude of the effect on the Corporation’s financial statements.
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting,
refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity
with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect
the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The
Corporation’s accounting policies are summarized in Note 1.
Oil and 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
56
The percentage of proved developed reserves was 66 percent of total proved reserves at year-end 2017 (including both
consolidated and equity company reserves), a reduction from 69 percent in 2016, 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.
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 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. The effect of this approach on the Corporation’s
2018 depreciation expense versus 2017 is anticipated to be immaterial.
Impairment
The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events or 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 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
57
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 and changes in circumstances such as a history of operating losses, an
indicator of potential impairment for certain assets.
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 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. As
part of its 2017 annual planning and budgeting cycle, the Corporation identified emerging trends such as increasing estimates of
available natural gas supplies and ongoing reductions in the industry’s costs of supply for natural gas that resulted in a reduction to
the Corporation’s long-term natural gas price outlooks. Based in part on these trends, the Corporation concluded that events and
circumstances indicated that the carrying value of certain long-lived assets, notably North America natural gas assets and certain
other assets across the remainder of its Upstream operations, may not be recoverable. Accordingly, an impairment assessment was
performed which indicated that the vast majority of asset groups assessed have future undiscounted cash flow estimates that exceed
their carrying values. However, the carrying values for certain asset groups in the United States exceeded the estimated cash flows.
As a result, the Corporation’s fourth quarter 2017 results include an after-tax charge of $0.5 billion to reduce the carrying value of
those assets to fair value. The asset groups subject to this impairment charge are primarily dry gas operations with little additional
development potential. In addition, the Corporation made a decision to cease development planning activities and further allocation
of capital to certain non-producing assets outside the United States. The Corporation’s fourth quarter 2017 results include an after-
tax charge of $0.8 billion to reduce the carrying value of those assets. Other impairments during the year resulted in an after-tax
charge of $0.2 billion.
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 5.5 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
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
58
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.
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).
Asset Retirement Obligations
The Corporation incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a
discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses
assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical
assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement
obligations are disclosed in Note 9 to the financial statements.
Suspended Exploratory Well Costs
The Corporation continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to
justify its completion as a producing well and the Corporation is making sufficient progress assessing the reserves and the economic
and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and
circumstances that support continued capitalization of suspended wells at year-end are disclosed in Note 10 to the financial
statements.
Consolidations
The Consolidated Financial Statements include the accounts of 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
59
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 2017 was 6.50 percent. The 10-year and
20-year actual returns on U.S. pension plan assets were 5 percent and 8 percent, respectively. The Corporation establishes the
long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class,
taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of
return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for
each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension
expense by approximately $170 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the
year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into
pension expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending
lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for
accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 16.
The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount
can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against
third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises
such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are
significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For
purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management
believes should be disclosed.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict.
However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect
on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards
are often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required
in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in
the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax
authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest
amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken
or expected to be taken in an income tax return and the amount recognized in the financial statements. The Corporation’s
unrecognized tax benefits and a description of open tax years are summarized in Note 19.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars
is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional
currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional
currency after evaluating this economic environment.
Factors considered by management when determining the functional currency for a subsidiary include the currency used for cash
flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of
inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services
and supplies; sources of financing; and significance of intercompany transactions.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
60
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, 2017.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s
internal control over financial reporting as of December 31, 2017, 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)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
61
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, 2017 and 2016, 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, 2017, 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, 2017 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, 2017 and 2016, and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2017 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, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, in 2017 the Corporation changed the manner in which it accounts
for certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with customers and
collected on behalf of governmental authorities.
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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
62
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 28, 2018
We have served as the Corporation’s auditor since 1934.
CONSOLIDATED STATEMENT OF INCOME
63
Note
Reference
Number 2017 2016 2015
(millions of dollars)
Revenues and other income
Sales and other operating revenue (1) 2 237,162 200,628 239,854
Income from equity affiliates 7 5,380 4,806 7,644
Other income 1,821 2,680 1,750
Total revenues and other income 244,363 208,114 249,248
Costs and other deductions
Crude oil and product purchases 128,217 104,171 130,003
Production and manufacturing expenses 34,128 31,927 35,587
Selling, general and administrative expenses 10,956 10,799 11,501
Depreciation and depletion 9 19,893 22,308 18,048
Exploration expenses, including dry holes 1,790 1,467 1,523
Interest expense 601 453 311
Other taxes and duties 2, 19 30,104 29,020 30,309
Total costs and other deductions 225,689 200,145 227,282
Income before income taxes 18,674 7,969 21,966
Income taxes 19 (1,174) (406) 5,415
Net income including noncontrolling interests 19,848 8,375 16,551
Net income attributable to noncontrolling interests 138 535 401
Net income attributable to ExxonMobil 19,710 7,840 16,150
Earnings per common share (dollars) 12 4.63 1.88 3.85
Earnings per common share – assuming dilution (dollars) 12 4.63 1.88 3.85
(1) Effective December 31, 2017, the Corporation revised its accounting policy election related to sales-based taxes. See Note 2:
Accounting Changes.
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
64
2017 2016 2015
(millions of dollars)
Net income including noncontrolling interests 19,848 8,375 16,551
Other comprehensive income (net of income taxes)
Foreign exchange translation adjustment 5,352 (174) (9,303)
Adjustment for foreign exchange translation (gain)/loss
included in net income 234 – (14)
Postretirement benefits reserves adjustment (excluding amortization) (219) 493 2,358
Amortization and settlement of postretirement benefits reserves
adjustment included in net periodic benefit costs 1,165 1,086 1,448
Unrealized change in fair value of stock investments – – 33
Realized (gain)/loss from stock investments included in net income – – 27
Total other comprehensive income 6,532 1,405 (5,451)
Comprehensive income including noncontrolling interests 26,380 9,780 11,100
Comprehensive income attributable to noncontrolling interests 693 668 (496)
Comprehensive income attributable to ExxonMobil 25,687 9,112 11,596
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED BALANCE SHEET
65
Note
Reference Dec. 31 Dec. 31
Number 2017 2016
(millions of dollars)
Assets
Current assets
Cash and cash equivalents 3,177 3,657
Notes and accounts receivable, less estimated doubtful amounts 6 25,597 21,394
Inventories
Crude oil, products and merchandise 3 12,871 10,877
Materials and supplies 4,121 4,203
Other current assets 1,368 1,285
Total current assets 47,134 41,416
Investments, advances and long-term receivables 8 39,160 35,102
Property, plant and equipment, at cost, less accumulated depreciation
and depletion 9 252,630 244,224
Other assets, including intangibles, net 9,767 9,572
Total assets 348,691 330,314
Liabilities
Current liabilities
Notes and loans payable 6 17,930 13,830
Accounts payable and accrued liabilities 6 36,796 31,193
Income taxes payable 3,045 2,615
Total current liabilities 57,771 47,638
Long-term debt 14 24,406 28,932
Postretirement benefits reserves 17 21,132 20,680
Deferred income tax liabilities 19 26,893 34,041
Long-term obligations to equity companies 4,774 5,124
Other long-term obligations 19,215 20,069
Total liabilities 154,191 156,484
Commitments and contingencies 16
Equity
Common stock without par value
(9,000 million shares authorized, 8,019 million shares issued) 14,656 12,157
Earnings reinvested 414,540 407,831
Accumulated other comprehensive income (16,262) (22,239)
Common stock held in treasury
(3,780 million shares in 2017 and 3,871 million shares in 2016) (225,246) (230,424)
ExxonMobil share of equity 187,688 167,325
Noncontrolling interests 6,812 6,505
Total equity 194,500 173,830
Total liabilities and equity 348,691 330,314
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
66
Note
Reference
Number 2017 2016 2015
(millions of dollars)
Cash flows from operating activities
Net income including noncontrolling interests 19,848 8,375 16,551
Adjustments for noncash transactions
Depreciation and depletion 9 19,893 22,308 18,048
Deferred income tax charges/(credits) (8,577) (4,386) (1,832)
Postretirement benefits expense
in excess of/(less than) net payments 1,135 (329) 2,153
Other long-term obligation provisions
in excess of/(less than) payments (610) (19) (380)
Dividends received greater than/(less than) equity in current
earnings of equity companies 131 (579) (691)
Changes in operational working capital, excluding cash and debt
Reduction/(increase) – Notes and accounts receivable (3,954) (2,090) 4,692
– Inventories (1,682) (388) (379)
– Other current assets (117) 171 45
Increase/(reduction) – Accounts and other payables 5,104 915 (7,471)
Net (gain) on asset sales 5 (334) (1,682) (226)
All other items – net 5 (771) (214) (166)
Net cash provided by operating activities 30,066 22,082 30,344
Cash flows from investing activities
Additions to property, plant and equipment 5 (15,402) (16,163) (26,490)
Proceeds associated with sales of subsidiaries, property, plant
and equipment, and sales and returns of investments 5 3,103 4,275 2,389
Decrease/(increase) in restricted cash and cash equivalents – – 42
Additional investments and advances (5,507) (1,417) (607)
Other investing activities including collection of advances 2,076 902 842
Net cash used in investing activities (15,730) (12,403) (23,824)
Cash flows from financing activities
Additions to long-term debt 5 60 12,066 8,028
Reductions in long-term debt – – (26)
Additions to short-term debt 1,735 – –
Reductions in short-term debt (5,024) (314) (506)
Additions/(reductions) in commercial paper, and debt with
three months or less maturity 5 2,181 (7,459) 1,759
Cash dividends to ExxonMobil shareholders (13,001) (12,453) (12,090)
Cash dividends to noncontrolling interests (184) (162) (170)
Changes in noncontrolling interests (150) – –
Tax benefits related to stock-based awards – – 2
Common stock acquired (747) (977) (4,039)
Common stock sold – 6 5
Net cash used in financing activities (15,130) (9,293) (7,037)
Effects of exchange rate changes on cash 314 (434) (394)
Increase/(decrease) in cash and cash equivalents (480) (48) (911)
Cash and cash equivalents at beginning of year 3,657 3,705 4,616
Cash and cash equivalents at end of year 3,177 3,657 3,705
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
67
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, 2014 10,792 408,384 (18,957) (225,820) 174,399 6,665 181,064
Amortization of stock-based awards 828 – – – 828 – 828
Tax benefits related to stock-based awards 116 – – – 116 – 116
Other (124) – – – (124) – (124)
Net income for the year – 16,150 – – 16,150 401 16,551
Dividends – common shares – (12,090) – – (12,090) (170) (12,260)
Other comprehensive income – – (4,554) – (4,554) (897) (5,451)
Acquisitions, at cost – – – (4,039) (4,039) – (4,039)
Dispositions – – – 125 125 – 125
Balance as of December 31, 2015 11,612 412,444 (23,511) (229,734) 170,811 5,999 176,810
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
Held in
Common Stock Share Activity Issued Treasury Outstanding
(millions of shares)
Balance as of December 31, 2014 8,019 (3,818) 4,201
Acquisitions – (48) (48)
Dispositions – 3 3
Balance as of December 31, 2015 8,019 (3,863) 4,156
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
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
68
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the
management of Exxon Mobil Corporation.
The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude
oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation
is also a major worldwide manufacturer and marketer of petrochemicals (Chemical).
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires
management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of
contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain
cases to conform to the 2017 presentation basis.
1. Summary of Accounting Policies
Principles of Consolidation
The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the
Corporation’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses. Amounts representing
the Corporation’s interest in entities that it does not control, but over which it exercises significant influence, are included in
“Investments, advances and long-term receivables”. The Corporation’s share of the net income of these companies is included in
the Consolidated Statement of Income caption “Income from equity affiliates”.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain
factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity
method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive
participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and
management compensation and succession plans.
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.
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. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has
assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.
Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized
on the basis of the Corporation’s net working interest. Differences between actual production and net working interest volumes are
not significant.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined
and recorded as exchanges measured at the book value of the item sold.
Taxes on Sales Transactions
Beginning in 2017, the Corporation revised its reporting of certain sales and value-added taxes imposed on and concurrent with
revenue-producing transactions with customers and collected on behalf of governmental authorities (sales-based taxes). This
changes reporting of sales-based taxes from gross reporting (included in both “Sales and other operating revenue” and “Sales-based
taxes”) to net reporting (excluded from both “Sales and other operating revenue” and “Sales-based taxes”) in the Consolidated
Statement of Income. This change in reporting was applied retrospectively and does not affect earnings. Similar taxes, for which
the Corporation is not considered to be an agent for the government, continue to be reported on a gross basis.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
69
Derivative Instruments
The Corporation has the ability to use derivative instruments to offset exposures associated with commodity prices, foreign currency
exchange rates and interest rates that arise from existing assets, liabilities and forecasted transactions. The gains and losses resulting
from changes in the fair value of derivatives are recorded in income.
The Corporation may designate derivatives as fair value hedges or cash flow hedges. For fair value hedges, the gain or loss on the
derivative and the offsetting loss or gain on the hedged item are recognized in current earnings. For cash flow hedges, the effective
part of the hedge 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 part of the hedge 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.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
70
Impairment Assessment. The Corporation tests assets or groups of assets for recoverability on an ongoing basis whenever events
or 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 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 and changes in circumstances such as a history of operating losses, an
indicator of potential impairment for certain assets.
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 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
71
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.
Stock-Based Payments
The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock units.
Compensation expense is measured by the price of the stock at the date of grant and is recognized in income over the requisite
service period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
72
2. Accounting Changes
Effective December 31, 2017, the Corporation revised its accounting policy election related to the reporting of certain sales and
value-added taxes imposed on and concurrent with revenue-producing transactions with customers and collected on behalf of
governmental authorities (sales-based taxes). This changes reporting of sales-based taxes from gross reporting (included in both
“Sales and other operating revenue” and “Sales-based taxes”) to the preferable method of net reporting (excluded from both “Sales
and other operating revenue” and “Sales-based taxes”) in the Consolidated Statement of Income. The revised election makes
reported revenue more consistent with ExxonMobil’s role as an agent for the government and is more consistent with the reporting
practices of other international major oil and gas companies and the largest U.S. companies. This change in accounting principle
was applied retrospectively and does not affect net income attributable to ExxonMobil.
Also effective December 31, 2017, the Corporation reclassified U.S. Federal excise tax from “Sales-based taxes” to “Other taxes
and duties”. For these taxes ExxonMobil is not considered to be an agent for the government and these taxes will continue to be
reported gross. The amount reclassified was $3,110 million in 2016 and $3,044 million in 2015. This change in classification was
applied retrospectively and does not affect net income attributable to ExxonMobil.
2016 2015
As Reported Change As Adjusted As Reported Change As Adjusted
(millions of dollars)
Sales and other operating revenue 218,608 (17,980) 200,628 259,488 (19,634) 239,854
Sales-based taxes 21,090 (21,090) – 22,678 (22,678) –
Other taxes and duties 25,910 3,110 29,020 27,265 3,044 30,309
Effective January 1, 2018, ExxonMobil adopted the Financial Accounting Standards Board’s standard, Revenue from Contracts
with Customers, 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 on the impact of
the new standard must be provided for 2018 results, if material. The standard is not expected to have a material impact on the
Corporation’s financial statements. The cumulative effect of adoption of the new standard is de minimis.
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. Companies can elect a modified approach for equity securities that
do not have a readily determinable fair value. The standard is not expected to have a material impact on the Corporation’s financial
statements.
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 the service cost component of net benefit costs to be reported in the same line of the income statement as other
compensation costs and the other components of net benefit costs (non-service costs) to be presented separately from the service
cost component. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The Corporation
expects to add a new line “Non-service pension and postretirement benefit expense” to its Consolidated Statement of Income and
expects to include all of these costs in its Corporate and financing segment. This line would reflect the non-service costs that were
previously included in “Production and manufacturing expenses” and “Selling, general and administrative expenses”. The update
is not expected to have a material impact on the Corporation’s financial statements.
Effective January 1, 2019, ExxonMobil will adopt the Financial Accounting Standards Board’s standard, Leases. The standard
requires all leases with an initial term greater than one year be recorded on the balance sheet as an asset and a lease liability. The
Corporation is gathering and evaluating data and recently acquired a system to facilitate implementation. We are progressing an
assessment of the magnitude of the effect on the Corporation’s financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
73
3. Miscellaneous Financial Information
Research and development expenses totaled $1,063 million in 2017, $1,058 million in 2016, and $1,008 million in 2015.
Net income included before-tax aggregate foreign exchange transaction gains of $6 million in 2017 and $29 million in 2016, and a
loss of $119 million in 2015.
In 2017, 2016, and 2015, net income included losses of $10 million, $295 million, and $186 million, respectively, attributable to
the combined effects of LIFO inventory accumulations and drawdowns. The aggregate replacement cost of inventories was
estimated to exceed their LIFO carrying values by $10.8 billion and $8.1 billion at December 31, 2017, and 2016, respectively.
Crude oil, products and merchandise as of year-end 2017 and 2016 consist of the following:
2017 2016
(billions of dollars)
Crude oil 4.6 3.9
Petroleum products 4.3 3.7
Chemical products 3.3 2.8
Gas/other 0.7 0.5
Total 12.9 10.9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
74
4. Other Comprehensive Income Information
Cumulative Post-
Foreign retirement Unrealized
Exchange Benefits Change in
ExxonMobil Share of Accumulated Other Translation Reserves Stock
Comprehensive Income Adjustment Adjustment Investments Total
(millions of dollars)
Balance as of December 31, 2014 (5,952) (12,945) (60) (18,957)
Current period change excluding amounts reclassified
from accumulated other comprehensive income (8,204) 2,202 33 (5,969)
Amounts reclassified from accumulated other
comprehensive income (14) 1,402 27 1,415
Total change in accumulated other comprehensive income (8,218) 3,604 60 (4,554)
Balance as of December 31, 2015 (14,170) (9,341) – (23,511)
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)
Amounts Reclassified Out of Accumulated Other
Comprehensive Income – Before-tax Income/(Expense) 2017 2016 2015
(millions of dollars)
Foreign exchange translation gain/(loss) included in net income
(Statement of Income line: Other income) (234) – 14
Amortization and settlement of postretirement benefits reserves
adjustment included in net periodic benefit costs (1) (1,656) (1,531) (2,066)
Realized change in fair value of stock investments included in net income
(Statement of Income line: Other income) – – (42)
(1) These accumulated other comprehensive income components are included in the computation of net periodic pension cost.
(See Note 17 – Pension and Other Postretirement Benefits for additional details.)
Income Tax (Expense)/Credit For
Components of Other Comprehensive Income 2017 2016 2015
(millions of dollars)
Foreign exchange translation adjustment 67 43 170
Postretirement benefits reserves adjustment (excluding amortization) 201 (247) (1,192)
Amortization and settlement of postretirement benefits reserves
adjustment included in net periodic benefit costs (491) (445) (618)
Unrealized change in fair value of stock investments – – (17)
Realized change in fair value of stock investments included in net income – – (15)
Total (223) (649) (1,672)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
75
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 2017, the “Net (gain) on asset sales” on the Consolidated Statement of Cash Flows 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. For 2015, the number includes
before-tax amounts from the sale of service stations in Europe, the sale of Upstream properties in the U.S., the sale of ExxonMobil’s
interests in Chemical and Refining joint ventures, and the sale of the Torrance refinery. These net gains are reported in “Other
income” on the Consolidated Statement of Income.
In 2017, the “Additions/(reductions) in commercial paper, and debt with three months or less maturity” on the Consolidated
Statement of Cash Flows 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 2015, the number includes a net $358 million addition of commercial paper with maturity over three
months. The gross amount issued was $8.1 billion, while the gross amount repaid was $7.7 billion.
In 2017, the Corporation completed the acquisitions of InterOil Corporation and of companies that own certain oil and gas properties
in the Permian basin and other assets. These transactions included a significant noncash component. Additional information is
provided in Note 20.
In 2015, ExxonMobil completed an asset exchange that resulted in value received of approximately $500 million including
$100 million in cash. The noncash portion was not included in the “Sales of subsidiaries, investments, and property, plant and
equipment” or the “All other items-net” lines on the Statement of Cash Flows. Capital leases of approximately $1 billion were not
included in the “Additions to long-term debt” or “Additions to property, plant and equipment” lines on the Statement of Cash Flows.
2017 2016 2015
(millions of dollars)
Cash payments for interest 1,132 818 586
Cash payments for income taxes 7,510 4,214 7,269
6. Additional Working Capital Information
Dec. 31 Dec. 31
2017 2016
(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $72 million and $75 million 21,274 16,033
Other, less reserves of $539 million and $627 million 4,323 5,361
Total 25,597 21,394
Notes and loans payable
Bank loans 115 143
Commercial paper 13,049 10,727
Long-term debt due within one year 4,766 2,960
Total 17,930 13,830
Accounts payable and accrued liabilities
Trade payables 21,701 17,801
Payables to equity companies 5,453 4,748
Accrued taxes other than income taxes 3,311 2,653
Other 6,331 5,991
Total 36,796 31,193
The Corporation has short-term committed lines of credit of $5.4 billion which were unused as of December 31, 2017. These lines
are available for general corporate purposes.
The weighted-average interest rate on short-term borrowings outstanding was 1.3 percent and 0.6 percent at December 31, 2017,
and 2016, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
76
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; and exploration, production, liquefied natural gas (LNG)
operations, refining operations, petrochemical manufacturing, and fuel sales 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 15 percent, 14 percent and
15 percent in the years 2017, 2016 and 2015, 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.
In 2013 and 2014, the Corporation and Rosneft established various entities to conduct exploration and research activities. In 2014,
the European Union and United States imposed sanctions relating to the Russian energy sector. In the latter half of 2017, the United
States codified and expanded sanctions against Russia. With respect to the foregoing, the Corporation and its affiliates continue to
comply with all applicable laws, rules and regulations. In late 2017, the Corporation decided to withdraw from these joint ventures.
The Corporation expects it will formally initiate the withdrawal in 2018. The decision to withdraw resulted in an after-tax loss of
$0.2 billion.
In 2017, the Corporation invested about $3 billion to acquire shares in four joint venture companies, resulting in a 25 percent
indirect interest in the natural gas-rich Area 4 block offshore Mozambique. The transaction was completed on December 13, 2017.
The investments are accounted for using the equity method of accounting.
2017 2016 2015
Equity Company ExxonMobil ExxonMobil ExxonMobil
Financial Summary Total Share Total Share Total Share
(millions of dollars)
Total revenues 94,791 29,340 80,247 24,668 111,866 34,297
Income before income taxes 29,748 8,498 22,269 6,509 36,379 10,670
Income taxes 8,421 2,236 6,334 1,701 11,048 3,019
Income from equity affiliates 21,327 6,262 15,935 4,808 25,331 7,651
Current assets 35,367 12,050 34,412 11,392 32,879 11,244
Long-term assets 122,221 34,931 109,646 32,357 109,684 32,878
Total assets 157,588 46,981 144,058 43,749 142,563 44,122
Current liabilities 21,725 6,348 20,507 5,765 22,947 6,738
Long-term liabilities 59,736 17,056 62,110 17,288 60,388 17,165
Net assets 76,127 23,577 61,441 20,696 59,228 20,219
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
77
A list of significant equity companies as of December 31, 2017, 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
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 (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
Infineum Italia s.r.l. 50
Infineum Singapore Pte. Ltd. 50
Infineum USA L.P. 50
Saudi Yanbu Petrochemical Co. 50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
78
8. Investments, Advances and Long-Term Receivables
Dec. 31, Dec. 31,
2017 2016
(millions of dollars)
Companies carried at equity in underlying assets
Investments 24,354 20,810
Advances 9,112 9,443
Total equity company investments and advances 33,466 30,253
Companies carried at cost or less and stock investments carried at fair value 174 154
Long-term receivables and miscellaneous investments at cost or less, net of reserves
of $5,432 million and $4,141 million 5,520 4,695
Total 39,160 35,102
9. Property, Plant and Equipment and Asset Retirement Obligations
December 31, 2017 December 31, 2016
Property, Plant and Equipment Cost Net Cost Net
(millions of dollars)
Upstream 371,904 200,291 355,265 195,904
Downstream 50,343 21,732 47,915 20,588
Chemical 37,966 20,117 34,098 17,401
Other 16,972 10,490 16,637 10,331
Total 477,185 252,630 453,915 244,224
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. As
part of its 2017 annual planning and budgeting cycle, the Corporation identified emerging trends such as increasing estimates of
available natural gas supplies and ongoing reductions in the industry’s costs of supply for natural gas that resulted in a reduction to
the Corporation’s long-term natural gas price outlooks. Based in part on these trends, the Corporation concluded that events and
circumstances indicated that the carrying value of certain long-lived assets, notably North America natural gas assets and certain
other assets across the remainder of its Upstream operations, may not be recoverable. Accordingly, an impairment assessment was
performed which indicated that the vast majority of asset groups assessed have future undiscounted cash flow estimates that exceed
their carrying values. However, the carrying values for certain asset groups in the United States exceeded the estimated cash flows.
As a result, the Corporation’s fourth quarter 2017 results include a before-tax charge of $0.8 billion to reduce the carrying value of
those assets to fair value. The asset groups subject to this impairment charge are primarily dry gas operations with little additional
development potential. In addition, the Corporation made a decision to cease development planning activities and further allocation
of capital to certain non-producing assets outside the United States resulting in a before-tax charge of $0.9 billion to reduce the
carrying value of those assets that are included in Property, Plant and Equipment. Other impairments during the year resulted in a
before-tax charge of $0.3 billion. The impairment charges are recognized primarily in the line “Depreciation and depletion” on the
Consolidated Statement of Income.
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 5.5 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.
Accumulated depreciation and depletion totaled $224,555 million at the end of 2017 and $209,691 million at the end of 2016.
Interest capitalized in 2017, 2016 and 2015 was $749 million, $708 million and $482 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
79
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:
2017 2016
(millions of dollars)
Beginning balance 13,243 13,704
Accretion expense and other provisions 780 740
Reduction due to property sales (906) (134)
Payments made (730) (549)
Liabilities incurred 128 204
Foreign currency translation 611 (513)
Revisions (421) (209)
Ending balance 12,705 13,243
The long-term Asset Retirement Obligations were $11,928 million and $12,352 million at December 31, 2017, and 2016,
respectively, and are included in Other long-term obligations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
80
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:
2017 2016 2015
(millions of dollars)
Balance beginning at January 1 4,477 4,372 3,587
Additions pending the determination of proved reserves 906 180 847
Charged to expense (1,205) (111) (5)
Reclassifications to wells, facilities and equipment based on the
determination of proved reserves (497) – (43)
Divestments/Other 19 36 (14)
Ending balance at December 31 3,700 4,477 4,372
Ending balance attributed to equity companies included above 306 707 696
Period end capitalized suspended exploratory well costs:
2017 2016 2015
(millions of dollars)
Capitalized for a period of one year or less 906 180 847
Capitalized for a period of between one and five years 1,345 2,981 2,386
Capitalized for a period of between five and ten years 1,064 911 826
Capitalized for a period of greater than ten years 385 405 313
Capitalized for a period greater than one year – subtotal 2,794 4,297 3,525
Total 3,700 4,477 4,372
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 greater than one year.
2017 2016 2015
Number of projects that only have exploratory well costs capitalized for a period
of one year or less 11 2 4
Number of projects that have exploratory well costs capitalized for a period
of greater than one year 46 58 55
Total 57 60 59
Of the 46 projects that have exploratory well costs capitalized for a period greater than one year as of December 31, 2017,
10 projects have drilling in the preceding year or exploratory activity planned in the next two years, while the remaining 36 projects
are those with completed exploratory activity progressing toward development.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
81
The table below provides additional detail for those 36 projects, which total $1,639 million.
Years
Dec. 31, Wells
Country/Project 2017 Drilled 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
– Perpetua-Zinia-Acacia 15 2008 – 2009 Oil field near Pazflor development, awaiting capacity in existing/planned
infrastructure.
Argentina
– La Invernada 72 2014 Evaluating development plan to tie into planned infrastructure.
Australia
– East Pilchard 8 2001 Gas field near Kipper/Tuna development, awaiting capacity in existing/
planned infrastructure.
– SE Longtom 12 2010 Gas field near Tuna development, awaiting capacity in existing/planned
infrastructure.
– SE Remora 36 2010 Gas field near Marlin development, awaiting capacity in existing/planned
infrastructure.
Indonesia
– Kedung Keris 11 2011 Development activity under way to tie into planned production facilities.
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 development alternatives, while continuing discussions with the
government regarding development plan.
Malaysia
– Bindu 2 1995 Awaiting capacity in existing/planned infrastructure.
Nigeria
– Bolia 15 2002 – 2006 Evaluating development plan, while continuing discussions with the
government regarding regional hub strategy.
– Bosi 79 2002 – 2006 Development activity under way, while continuing discussions with the
government regarding development plan.
– Bosi Central 16 2006 Development activity under way, while continuing discussions with the
government regarding development plan.
– Erha Northeast 26 2008 Evaluating development plan for tieback to existing production facilities.
– OML 138 Ukot SW 41 2014 Evaluating development plan for tieback to existing production facilities.
– OML 138 Ukot SS 13 2015 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 (3 projects) 7 2002 Evaluating and pursuing development of several additional discoveries.
Norway
– Gamma 14 2008 – 2009 Evaluating development plan for tieback to existing production facilities.
– Lavrans 16 1995 – 1999 Evaluating development plan, awaiting capacity in existing Kristin
production facility.
– Other (7 projects) 27 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
82
Years
Dec. 31, Wells
Country/Project 2017 Drilled Comment
(millions of dollars)
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 Development planning activity under way, while continuing commercial
discussions with the government.
Total 2017 (36 projects) 1,639
11. Leased Facilities
At December 31, 2017, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering
drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $4,290
million as indicated in the table. Estimated related sublease rental income from noncancelable subleases totals $36 million.
Lease Payments
Under Minimum Commitments
Drilling Rigs
and Related
Equipment Other Total
(millions of dollars)
2018 169 767 936
2019 131 537 668
2020 101 397 498
2021 70 297 367
2022 41 259 300
2023 and beyond 99 1,422 1,521
Total 611 3,679 4,290
Net rental cost under both cancelable and noncancelable operating leases incurred during 2017, 2016 and 2015 were as follows:
2017 2016 2015
(millions of dollars)
Rental cost
Drilling rigs and related equipment 792 1,274 1,853
Other (net of sublease rental income) 1,826 1,817 2,076
Total 2,618 3,091 3,929
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
83
12. Earnings Per Share
Earnings per common share 2017 2016 2015
Net income attributable to ExxonMobil (millions of dollars) 19,710 7,840 16,150
Weighted average number of common shares outstanding (millions of shares) 4,256 4,177 4,196
Earnings per common share (dollars) (1) 4.63 1.88 3.85
Dividends paid per common share (dollars) 3.06 2.98 2.88
(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 fair value of financial instruments is determined by reference to observable market data and other
valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and
recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, excluding capitalized lease
obligations, was $23.7 billion and $28.0 billion at December 31, 2017, and 2016, respectively, as compared to recorded book values
of $23.1 billion and $27.7 billion at December 31, 2017, and 2016, respectively.
The fair value of long-term debt by hierarchy level at December 31, 2017, is: Level 1 $23,529 million; Level 2 $170 million; and
Level 3 $6 million.
Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of
the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates,
currency rates and commodity prices. In addition, the Corporation uses commodity-based contracts, including derivatives, to
manage commodity price risk and for trading purposes. 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 believes that there are no material market or credit risks to the Corporation’s financial position,
results of operations or liquidity as a result of the derivatives. The Corporation maintains a system of controls that includes the
authorization, reporting and monitoring of derivative activity.
The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net liability of $38 million
at year-end 2017 and a net liability of $22 million at year-end 2016. Assets and liabilities associated with derivatives are usually
recorded either in “Other current assets” or “Accounts payable and accrued liabilities”.
The Corporation’s fair value measurement of its derivative instruments use either Level 1 or Level 2 inputs.
The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $(99) million, $(81) million and
$39 million during 2017, 2016 and 2015, respectively. Income statement effects associated with derivatives are usually recorded
either in “Sales and other operating revenue” or “Crude oil and product purchases”.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
84
14. Long-Term Debt
At December 31, 2017, long-term debt consisted of $23,736 million due in U.S. dollars and $670 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 $4,766 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, 2018, in millions of dollars, are:
2019 – $4,045; 2020 – $1,617; 2021 – $2,549; and 2022 – $1,835. At December 31, 2017, the Corporation’s unused long-term
credit lines were $0.2 billion.
Summarized long-term debt at year-end 2017 and 2016 are shown in the table below:
Average
Rate (1) 2017 2016
(millions of dollars)
Exxon Mobil Corporation
1.305% notes due 2018 – 1,600
1.439% notes due 2018 – 1,000
Floating-rate notes due 2018 (Issued 2016) – 750
Floating-rate notes due 2018 (Issued 2015) – 500
1.819% notes due 2019 1,750 1,750
1.708% notes due 2019 1,250 1,250
Floating-rate notes due 2019 (Issued 2014) 1.345% 500 500
Floating-rate notes due 2019 (Issued 2016) 1.953% 250 250
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 1.557% 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)
5.500% senior notes due 2018 – 371
6.500% senior notes due 2018 – 453
6.100% senior notes due 2036 195 197
6.750% senior notes due 2037 302 304
6.375% senior notes due 2038 232 233
Mobil Corporation
8.625% debentures due 2021 250 249
Industrial revenue bonds due 2019-2051 0.764% 2,559 2,559
Other U.S. dollar obligations 162 103
Other foreign currency obligations 34 57
Capitalized lease obligations 8.504% 1,327 1,225
Debt issuance costs (55) (69)
Total long-term debt 24,406 28,932
(1) Average effective interest rate for debt and average imputed interest rate for capital leases at December 31, 2017.
(2) Includes premiums of $102 million in 2017 and $138 million in 2016.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
85
15. Incentive Program
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms
of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned.
Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs
may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The
maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited,
expire or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term.
New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2017,
remaining shares available for award under the 2003 Incentive Program were 89 million.
Restricted Stock and Restricted Stock Units. Awards totaling 8,916 thousand, 9,583 thousand, and 9,681 thousand of restricted
(nonvested) common stock units were granted in 2017, 2016 and 2015, 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, 2017.
2017
Weighted Average
Grant-Date
Restricted stock and units outstanding Shares Fair Value per Share
(thousands) (dollars)
Issued and outstanding at January 1 43,833 84.43
2016 award issued in 2017 9,582 87.70
Vested (10,136) 80.71
Forfeited (2,201) 80.11
Issued and outstanding at December 31 41,078 86.34
Value of restricted stock and units 2017 2016 2015
Grant price (dollars) 81.89 87.70 81.27
Value at date of grant: (millions of dollars)
Restricted stock and units settled in stock 667 771 727
Units settled in cash 63 69 60
Total value 730 840 787
As of December 31, 2017, there was $2,049 million of unrecognized compensation cost related to the nonvested restricted awards.
This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income
for the restricted stock and restricted stock units was $856 million, $880 million and $855 million for 2017, 2016 and 2015,
respectively. The income tax benefit recognized in income related to this compensation expense was $78 million, $80 million and
$78 million for the same periods, respectively. The fair value of shares and units vested in 2017, 2016 and 2015 was $826 million,
$851 million and $808 million, respectively. Cash payments of $64 million, $67 million and $64 million for vested restricted stock
units settled in cash were made in 2017, 2016 and 2015, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
86
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, 2017,
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, 2017
Equity Company Other Third-Party
Obligations (1) Obligations Total
(millions of dollars)
Guarantees
Debt-related 98 270 368
Other 1,191 4,514 5,705
Total 1,289 4,784 6,073
(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 nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the
Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had
been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also
required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s
ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed
enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture.
ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated
ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of
Investment Disputes (ICSID). The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed
on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. On October 9, 2014, the ICSID Tribunal issued its final
award finding in favor of the ExxonMobil affiliates and awarding $1.6 billion as of the date of expropriation, June 27, 2007, and
interest from that date at 3.25 percent compounded annually until the date of payment in full. The Tribunal also noted that one of
the Cerro Negro Project agreements provides a mechanism to prevent double recovery between the ICSID award and all or part of
an earlier award of $908 million to an ExxonMobil affiliate, Mobil Cerro Negro, Ltd., against PdVSA and a PdVSA affiliate,
PdVSA CN, in an arbitration under the rules of the International Chamber of Commerce.
On February 2, 2015, Venezuela filed a Request for Annulment of the ICSID award. On March 9, 2017, the ICSID Committee
hearing the Request for Annulment issued a decision partially annulling the award of the Tribunal issued on October 9, 2014. The
Committee affirmed the compensation due for the La Ceiba project and for export curtailments at the Cerro Negro project, but
annulled the portion of the award relating to the Cerro Negro Project’s expropriation ($1.4 billion) based on its determination that
the 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. As a result, ExxonMobil retains an award for $260 million (including
accrued interest). ExxonMobil reached an agreement with Venezuela for full payment of the $260 million and Venezuela has begun
performing on it. The agreement does not impact ExxonMobil’s ability to re-arbitrate the issue that was the basis for the annulment
in a new ICSID arbitration proceeding.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
87
The United States District Court for the Southern District of New York entered judgment on the ICSID award on October 10, 2014.
Motions filed by Venezuela to vacate that judgment on procedural grounds and to modify the judgment by reducing the rate of
interest to be paid on the ICSID award from the entry of the court’s judgment, until the date of payment, were denied on
February 13, 2015, and March 4, 2015, respectively. On March 9, 2015, Venezuela filed a notice of appeal of the court’s actions
on the two motions. On July 11, 2017, the United States Court of Appeals for the Second Circuit rendered its opinion overturning
the District Court’s decision and vacating the judgment on the grounds that a different procedure should have been used to reduce
the award to judgment. The Corporation is evaluating next steps.
A stay of the District Court’s judgment has continued pending the completion of the Second Circuit appeal. The net impact of these
matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not
expect the resolution to have a material effect upon the Corporation’s operations or financial condition.
An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National
Petroleum Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil’s affiliate is the
operator of the block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC’s
lifting of crude oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors
initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member
arbitral Tribunal issued an award upholding the Contractors’ position in all material respects and awarding damages to the
Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors petitioned a
Nigerian federal court for enforcement of the award, and NNPC petitioned the same court to have the award set aside. On
May 22, 2012, the court set aside the award. The Contractors appealed that judgment to the Court of Appeal, Abuja Judicial
Division. 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. The stay in the
proceedings in the Southern District of New York has been lifted. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
88
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
2017 2016 2017 2016 2017 2016
(percent)
Weighted-average assumptions used to determine
benefit obligations at December 31
Discount rate 3.80 4.25 2.80 3.00 3.80 4.25
Long-term rate of compensation increase 5.75 5.75 4.30 4.00 5.75 5.75
(millions of dollars)
Change in benefit obligation
Benefit obligation at January 1 19,960 19,583 25,196 25,117 7,800 8,282
Service cost 784 810 596 585 129 153
Interest cost 798 793 772 844 317 344
Actuarial loss/(gain) 733 250 250 1,409 231 (560)
Benefits paid (1) (2) (2,964) (1,476) (1,291) (1,228) (543) (537)
Foreign exchange rate changes – – 2,484 (1,520) 40 16
Amendments, divestments and other (1) – (44) (11) 126 102
Benefit obligation at December 31 19,310 19,960 27,963 25,196 8,100 7,800
Accumulated benefit obligation at December 31 15,557 16,245 25,557 22,867 – –
(1) Benefit payments for funded and unfunded plans.
(2) For 2017 and 2016, other postretirement benefits paid are net of $16 million and $22 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 2019
and subsequent years. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by
$72 million and the postretirement benefit obligation by $696 million. A one-percentage-point decrease in the health care cost trend
rate would decrease service and interest cost by $53 million and the postretirement benefit obligation by $536 million.
Pension Benefits Other Postretirement
U.S. Non-U.S. Benefits
2017 2016 2017 2016 2017 2016
(millions of dollars)
Change in plan assets
Fair value at January 1 12,793 10,985 19,043 18,417 411 414
Actual return on plan assets 1,831 949 1,442 2,443 40 20
Foreign exchange rate changes – – 1,776 (1,452) – –
Company contribution 619 2,068 440 492 34 36
Benefits paid (1) (2,461) (1,209) (902) (857) (58) (59)
Other – – (338) – – –
Fair value at December 31 12,782 12,793 21,461 19,043 427 411
(1) Benefit payments for funded plans.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
89
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.
2017 2016 2017 2016
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans (3,957) (4,306) 413 212
Unfunded plans (2,571) (2,861) (6,915) (6,365)
Total (6,528) (7,167) (6,502) (6,153)
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
2017 2016 2017 2016 2017 2016
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1) (6,528) (7,167) (6,502) (6,153) (7,673) (7,389)
Amounts recorded in the consolidated balance
sheet consist of:
Other assets – – 1,403 1,035 – –
Current liabilities (276) (409) (338) (294) (360) (361)
Postretirement benefits reserves (6,252) (6,758) (7,567) (6,894) (7,313) (7,028)
Total recorded (6,528) (7,167) (6,502) (6,153) (7,673) (7,389)
Amounts recorded in accumulated other
comprehensive income consist of:
Net actuarial loss/(gain) 3,982 5,354 5,586 5,629 1,595 1,468
Prior service cost 11 15 (143) (123) (397) (430)
Total recorded in accumulated other
comprehensive income 3,993 5,369 5,443 5,506 1,198 1,038
(1) Fair value of assets less benefit obligation shown on the preceding page.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
90
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
2017 2016 2015 2017 2016 2015 2017 2016 2015
Weighted-average assumptions used to
determine net periodic benefit cost for
years ended December 31 (percent)
Discount rate 4.25 4.25 4.00 3.00 3.60 3.10 4.25 4.25 4.00
Long-term rate of return on funded assets 6.50 6.50 7.00 5.20 5.25 5.90 6.50 6.50 7.00
Long-term rate of compensation increase 5.75 5.75 5.75 4.00 4.80 5.30 5.75 5.75 5.75
Components of net periodic benefit cost (millions of dollars)
Service cost 784 810 864 596 585 689 129 153 170
Interest cost 798 793 785 772 844 850 317 344 346
Expected return on plan assets (775) (726) (830) (1,000) (927) (1,094) (24) (25) (28)
Amortization of actuarial loss/(gain) 438 492 544 476 536 730 96 153 206
Amortization of prior service cost 5 6 6 47 54 87 (33) (30) (24)
Net pension enhancement and
curtailment/settlement cost 609 319 499 19 2 22 – – –
Net periodic benefit cost 1,859 1,694 1,868 910 1,094 1,284 485 595 670
Changes in amounts recorded in accumulated
other comprehensive income:
Net actuarial loss/(gain) (324) 27 592 (191) (156) (1,375) 215 (555) (589)
Amortization of actuarial (loss)/gain (1,047) (811) (1,043) (495) (538) (752) (96) (153) (206)
Prior service cost/(credit) – – – 111 32 (401) – – (535)
Amortization of prior service (cost)/credit (5) (6) (6) (47) (54) (87) 33 30 24
Foreign exchange rate changes – – – 559 (108) (1,126) 8 5 (31)
Total recorded in other comprehensive income (1,376) (790) (457) (63) (824) (3,741) 160 (673) (1,337)
Total recorded in net periodic benefit cost and
other comprehensive income, before tax 483 904 1,411 847 270 (2,457) 645 (78) (667)
Costs for defined contribution plans were $384 million, $399 million and $405 million in 2017, 2016 and 2015, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
91
A summary of the change in accumulated other comprehensive income is shown in the table below:
Total Pension and
Other Postretirement Benefits
2017 2016 2015
(millions of dollars)
(Charge)/credit to other comprehensive income, before tax
U.S. pension 1,376 790 457
Non-U.S. pension 63 824 3,741
Other postretirement benefits (160) 673 1,337
Total (charge)/credit to other comprehensive income, before tax 1,279 2,287 5,535
(Charge)/credit to income tax (see Note 4) (290) (692) (1,810)
(Charge)/credit to investment in equity companies (43) (16) 81
(Charge)/credit to other comprehensive income including noncontrolling
interests, after tax 946 1,579 3,806
Charge/(credit) to equity of noncontrolling interests 12 24 (202)
(Charge)/credit to other comprehensive income attributable to ExxonMobil 958 1,603 3,604
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
92
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
93
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
Private equity – –
– – –
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
94
The 2016 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, 2016, Using: at December 31, 2016, 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. – – – 2,347 2,347 –
– – 3,343 3,343
Non-U.S. – – – 2,126 2,126 142 (2) 2 (3) – 3,632 3,776
Private equity – –
– 553 553 –
–
– 539 539
Debt securities
Corporate – 4,978 (4) – 1 4,979 – 123 (4) – 4,075 4,198
Government – 2,635 (4) – 1 2,636 167 (5) 32 (4) – 6,753 6,952
Asset-backed – 3 (4) – 1 4 –
35 (4) – 72 107
Cash – – – 137 137 23 9 (6) – 73 105
Total at fair value – 7,616 – 5,166 12,782 332 201 – 18,487 19,020
Insurance contracts
at contract value 11 23
Total plan assets 12,793 19,043
(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 U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the
published unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable
quoted prices on active exchanges, which are Level 1 inputs.
(4) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market
transactions.
(5) For government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(6) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
95
Other Postretirement
Fair Value Measurement
at December 31, 2016, Using:
Net
Asset
Level 1 Level 2 Level 3 Value (1) Total
(millions of dollars)
Asset category:
Equity securities
U.S. – – –
98
98
Non-U.S. – – –
71
71
Private equity – –
– – –
Debt securities
Corporate – 82 (2) –
–
82
Government – 159 (2) –
–
159
Asset-backed – 1 (2) –
–
1
Cash – –
–
–
–
Total at fair value – 242 – 169 411
(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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
96
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.
2017 2016 2017 2016
(millions of dollars)
For funded pension plans with an accumulated benefit obligation
in excess of plan assets:
Projected benefit obligation 16,739 17,099 3,384 837
Accumulated benefit obligation 14,022 14,390 3,264 612
Fair value of plan assets 12,782 12,793 3,219 564
For unfunded pension plans:
Projected benefit obligation 2,571 2,861 6,915 6,365
Accumulated benefit obligation 1,535 1,855 6,208 5,687
Other
Pension Benefits Postretirement
U.S. Non-U.S. Benefits
(millions of dollars)
Estimated 2018 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain) (1) 539 412 112
Prior service cost (2) 5 47 (40)
(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 2018 490 720 – –
Benefit payments expected in:
2018 1,364 1,183 459 25
2019 1,279 1,163 465 26
2020 1,267 1,197 469 28
2021 1,268 1,203 470 29
2022 1,285 1,220 468 30
2023 – 2027 6,355 6,162 2,329 174
18. Disclosures about Segments and Related Information
The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately.
The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment.
The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment
is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to
manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in
business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed
by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess
its performance; and (3) for which discrete financial information is available.
Earnings after income tax include transfers at estimated market prices.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
97
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 $136 million in 2017, $63 million in 2016 and $100 million in 2015.
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, 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 (1) 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
As of December 31, 2015
Earnings after income tax (1,079) 8,180 1,901 4,656 2,386 2,032 (1,926) 16,150
Earnings of equity companies included above 226 5,831 170 444 144 1,235 (406) 7,644
Sales and other operating revenue (1) 8,241 15,446 69,706 119,050 10,879 16,524 8 239,854
Intersegment revenue 4,344 20,839 12,440 22,166 7,442 5,168 274 –
Depreciation and depletion expense 5,301 9,227 664 1,003 375 654 824 18,048
Interest revenue – – – – – – 46 46
Interest expense 26 27 8 4 – 1 245 311
Income tax expense (benefit) (879) 4,703 866 1,325 646 633 (1,879) 5,415
Additions to property, plant and equipment 6,915 14,561 916 1,477 1,865 629 1,112 27,475
Investments in equity companies 5,160 10,980 95 1,179 125 3,025 (227) 20,337
Total assets 93,648 155,316 16,498 29,808 10,174 18,236 13,078 336,758
(1) Sales and other operating revenue excludes previously reported sales-based taxes of $17,980 million for 2016 and $19,634
million for 2015. See Note 2: Accounting Changes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
98
Geographic
Sales and other operating revenue (1) 2017 2016 2015
(millions of dollars)
United States 82,079 70,126 88,826
Non-U.S. 155,083 130,502 151,028
Total 237,162 200,628 239,854
Significant non-U.S. revenue sources include:
Canada 20,116 17,682 19,076
United Kingdom 16,611 15,452 20,605
Belgium 13,633 10,834 12,481
Singapore 11,589 9,919 10,632
Italy 11,476 9,715 11,220
France 11,235 9,487 10,631
Germany 8,484 7,899 8,447
(1) Sales and other operating revenue excludes previously reported sales-based taxes of $17,980 million for 2016 and $19,634
million for 2015. See Note 2: Accounting Changes.
Long-lived assets 2017 2016 2015
(millions of dollars)
United States 105,101 101,194 107,039
Non-U.S. 147,529 143,030 144,566
Total 252,630 244,224 251,605
Significant non-U.S. long-lived assets include:
Canada 41,138 40,144 39,775
Australia 16,908 16,510 15,894
Singapore 11,292 9,769 9,681
Kazakhstan 10,121 10,325 9,705
Nigeria 9,734 11,314 12,222
Papua New Guinea 8,463 5,719 5,985
Angola 7,689 8,413 8,777
Russia 5,702 4,828 4,744
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
99
19. Income and Other Taxes
2017 2016 2015
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 577 6,633 7,210 (214) 4,056 3,842 – 7,126 7,126
Deferred – net (9,075) 754 (8,321) (2,801) (1,422) (4,223) (1,166) (571) (1,737)
U.S. tax on non-U.S. operations 17 – 17 41 – 41 38 – 38
Total federal and non-U.S. (8,481) 7,387 (1,094) (2,974) 2,634 (340) (1,128) 6,555 5,427
State (80) – (80) (66) – (66) (12) – (12)
Total income tax expense (8,561) 7,387 (1,174) (3,040) 2,634 (406) (1,140) 6,555 5,415
All other taxes and duties
Other taxes and duties 3,330 26,774 30,104 3,209 25,811 29,020 3,206 27,103 30,309
Included in production and
manufacturing expenses 1,107 747 1,854 1,052 808 1,860 1,157 828 1,985
Included in SG&A expenses 147 354 501 133 362 495 150 390 540
Total other taxes and duties 4,584 27,875 32,459 4,394 26,981 31,375 4,513 28,321 32,834
Total (3,977) 35,262 31,285 1,354 29,615 30,969 3,373 34,876 38,249
Sales-based taxes were previously reported gross on the income statement and included in total taxes in the above table. See Note
2: Accounting Changes.
The above provisions for deferred income taxes include a net credit of $5,920 million in 2017, 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 also includes net charges of $180 million in 2016 and $177 million in 2015 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 guidance outlined in the SEC Staff Accounting Bulletin No. 118, the
Corporation has included reasonable estimates of the income tax effects of the changes in tax law and tax rate. These include
amounts for the remeasurement of the deferred income tax balance from the reduction in the corporate tax rate from 35 to 21 percent
and the mandatory deemed repatriation of undistributed foreign earnings and profits. The Corporation has paid taxes on earnings
outside the United States at tax rates on average above the historical U.S. rate of 35 percent. As a result, the deemed repatriation
tax does not create a significant tax impact for ExxonMobil. The impact of tax law changes on the Corporation’s financial statements
could differ from its estimates due to further analysis of the new law, regulatory guidance, technical corrections legislation, or
guidance under U.S. GAAP. If significant changes occur, the Corporation will provide updated information in connection with
future regulatory filings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
100
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2017, 2016
and 2015 is as follows:
2017 2016 2015
(millions of dollars)
Income before income taxes
United States (754) (5,832) 147
Non-U.S. 19,428 13,801 21,819
Total 18,674 7,969 21,966
Theoretical tax 6,536 2,789 7,688
Effect of equity method of accounting (1,883) (1,682) (2,675)
Non-U.S. taxes in excess of/(less than) theoretical U.S. tax (1) 1,848 (582) 1,415
Effect of U.S. tax reform (5,942) – –
Other (2) (1,733) (931) (1,013)
Total income tax expense (1,174) (406) 5,415
Effective tax rate calculation
Income taxes (1,174) (406) 5,415
ExxonMobil share of equity company income taxes 2,228 1,692 3,011
Total income taxes 1,054 1,286 8,426
Net income including noncontrolling interests 19,848 8,375 16,551
Total income before taxes 20,902 9,661 24,977
Effective income tax rate 5% 13% 34%
(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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
101
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. Balances at December 31, 2017, reflect the deferred
income tax effects from the enactment of the U.S. Tax Cuts and Jobs Act of 2017. The Corporation has elected to account for the
tax on global intangible low-taxed income (GILTI) as a tax expense in the period in which it is incurred.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
Tax effects of temporary differences for: 2017 2016
(millions of dollars)
Property, plant and equipment 36,559 46,744
Other liabilities 5,625 4,262
Total deferred tax liabilities 42,184 51,006
Pension and other postretirement benefits (4,338) (6,053)
Asset retirement obligations (4,237) (5,454)
Tax loss carryforwards (6,767) (5,472)
Other assets (5,832) (5,615)
Total deferred tax assets (21,174) (22,594)
Asset valuation allowances 2,565 1,509
Net deferred tax liabilities 23,575 29,921
In 2017, asset valuation allowances of $2,565 million increased by $1,056 million and included net provisions of $502 million,
$402 million recorded in the acquisition of InterOil Corporation, and effects of foreign currency translation of $152 million.
Balance sheet classification 2017 2016
(millions of dollars)
Other assets, including intangibles, net (3,318) (4,120)
Deferred income tax liabilities 26,893 34,041
Net deferred tax liabilities 23,575 29,921
The Corporation’s earnings from subsidiary companies outside the United States were subject to the deemed repatriation required
by the U.S. Tax Cuts and Jobs Act of 2017. Those amounts continue to be indefinitely reinvested and are retained to fund prior and
future capital project expenditures. Deferred income taxes have not been recorded for certain additional future tax obligations, such
as foreign withholding tax and state tax, as these earnings are expected to be indefinitely reinvested for the foreseeable future. As
of December 31, 2017, it is not practicable to estimate the unrecognized deferred income tax liability.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
102
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 2017 2016 2015
(millions of dollars)
Balance at January 1 9,468 9,396 8,986
Additions based on current year’s tax positions 522 655 903
Additions for prior years’ tax positions 523 534 496
Reductions for prior years’ tax positions (865) (1,019) (190)
Reductions due to lapse of the statute of limitations (113) (7) (4)
Settlements with tax authorities (782) (70) (725)
Foreign exchange effects/other 30 (21) (70)
Balance at December 31 8,783 9,468 9,396
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 2017, 2016 and 2015 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 2014 – 2017
Angola 2016 – 2017
Australia 2008 – 2017
Belgium 2015 – 2017
Canada 1998 – 2017
Equatorial Guinea 2007 – 2017
Indonesia 2007 – 2017
Iraq 2012 – 2017
Malaysia 2009 – 2017
Nigeria 2006 – 2017
Norway 2007 – 2017
Papua New Guinea 2008 – 2017
Russia 2015 – 2017
United Kingdom 2015 – 2017
United States 2006 – 2017
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 $36 million, $4 million and $39 million in interest expense on income tax reserves in 2017, 2016 and
2015, respectively. The related interest payable balances were $168 million and $191 million at December 31, 2017, and 2016,
respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
103
20. Acquisitions
InterOil Corporation
On February 22, 2017, the Corporation completed the acquisition of InterOil Corporation (IOC) for $2.7 billion. The IOC
acquisition was mostly unproved properties in Papua New Guinea. Consideration included 28 million shares of Exxon Mobil
Corporation common stock having a value on the acquisition date of $2.2 billion, a Contingent Resource Payment (CRP) with a
fair value of $0.3 billion and cash of $0.2 billion. The CRP provided IOC shareholders $7.07 per share in cash for each incremental
independently certified Trillion Cubic Feet Equivalent (TCFE) of resources above 6.2 TCFE, up to 11.0 TCFE. IOC’s assets include
a contingent receivable related to the same resource base for volumes in excess of 3.5 TCFE at amounts ranging from $0.24 – $0.40
per thousand cubic feet equivalent. The fair value of the contingent receivable was $1.1 billion at the acquisition date. Fair values
of contingent amounts were based on assumptions about the outcome of the resource certification, future business plans and
appropriate discount rates.
On September 6, 2017, the resource certification was finalized triggering both payment of the CRP to former IOC shareholders and
receipt of the current portion of the contingent receivable. The earnings impact from settlement of the CRP and the related
contingent receivable was not material.
Permian Basin Properties
On February 28, 2017, the Corporation completed the acquisition for $6.2 billion of a number of companies from the Bass family
in Fort Worth, Texas, that indirectly own mostly unproved oil and gas properties in the Permian Basin. Consideration included 68
million shares of Exxon Mobil Corporation common stock having a value on the acquisition date of $5.5 billion, together with
additional contingent cash payments tied to future drilling and completion activities (up to a maximum of $1.02 billion). Fair value
of the contingent payment was $0.7 billion as of the acquisition date and is expected to be paid beginning in 2020 and ending no
later than 2032 commensurate with development of the resource. Fair value of the contingent payment was based on assumptions
including drilling and completion activities, appropriate discount rates and tax rates.
The fair value of the contingent payment is adjusted each quarter. The earnings impact from these adjustments was not material.
Below is a summary of the net assets acquired for each acquisition.
IOC Permian
(billions of dollars)
Current assets 0.6 –
Property, plant and equipment 2.9 6.3
Other 0.6 –
Total assets 4.1 6.3
Current liabilities 0.5 –
Long-term liabilities 0.9 0.1
Total liabilities 1.4 0.1
Net assets acquired 2.7 6.2
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
104
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 $1,402 million in 2017, $719 million in 2016, and
$831 million in 2015. 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
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
105
Canada/
United Other Australia/
Results of Operations States Americas Europe Africa Asia Oceania Total
(millions of dollars)
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)
Consolidated Subsidiaries
2015 – Revenue
Sales to third parties 4,830 1,756 3,933 1,275 2,651 1,408 15,853
Transfers 2,557 2,858 2,024 8,135 4,490 608 20,672
7,387 4,614 5,957 9,410 7,141 2,016 36,525
Production costs excluding taxes 4,252 3,690 2,232 1,993 1,562 527 14,256
Exploration expenses 182 473 187 319 254 108 1,523
Depreciation and depletion 5,054 1,315 1,641 3,874 1,569 392 13,845
Taxes other than income 630 111 200 734 706 171 2,552
Related income tax (976) (79) 807 1,556 2,117 238 3,663
Results of producing activities for consolidated
subsidiaries (1,755) (896) 890 934 933 580 686
Equity Companies
2015 – Revenue
Sales to third parties 608 – 2,723 – 11,174 – 14,505
Transfers 459 – 31 – 379 – 869
1,067 – 2,754 – 11,553 – 15,374
Production costs excluding taxes 554 – 565 – 422 – 1,541
Exploration expenses 12 – 21 – 18 – 51
Depreciation and depletion 271 – 146 – 457 – 874
Taxes other than income 47 – 1,258 – 3,197 – 4,502
Related income tax – – 263 – 2,559 – 2,822
Results of producing activities for equity companies 183 – 501 – 4,900 – 5,584
Total results of operations (1,572) (896) 1,391 934 5,833 580 6,270
106
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $15,292 million less at year-end 2017 and
$15,239 million less at year-end 2016 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, 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
Consolidated Subsidiaries
As of December 31, 2016
Property (acreage) costs – Proved 16,075 2,339 134 929 1,739 736 21,952
– Unproved 22,747 4,030 25 291 269 115 27,477
Total property costs 38,822 6,369 159 1,220 2,008 851 49,429
Producing assets 91,651 40,291 33,811 51,307 34,690 11,730 263,480
Incomplete construction 2,099 6,154 1,403 4,495 8,377 2,827 25,355
Total capitalized costs 132,572 52,814 35,373 57,022 45,075 15,408 338,264
Accumulated depreciation and depletion 55,924 15,740 28,291 35,085 17,475 5,084 157,599
Net capitalized costs for consolidated subsidiaries 76,648 37,074 7,082 21,937 27,600 10,324 180,665
Equity Companies
As of December 31, 2016
Property (acreage) costs – Proved 77 – 3 – – – 80
– Unproved 12 – – – 59 – 71
Total property costs 89 – 3 – 59 – 151
Producing assets 6,326 – 5,043 – 8,646 – 20,015
Incomplete construction 109 – 40 – 4,791 – 4,940
Total capitalized costs 6,524 – 5,086 – 13,496 – 25,106
Accumulated depreciation and depletion 2,417 – 3,987 – 6,013 – 12,417
Net capitalized costs for equity companies 4,107 – 1,099 – 7,483 – 12,689
107
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 2017 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. In 2016 costs were $11,375
million, down $10,512 million from 2015, due primarily to lower development costs. Total equity company costs incurred in 2017
were $6,008 million, up $4,602 million from 2016, due primarily to acquisition 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 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
During 2015
Consolidated Subsidiaries
Property acquisition costs – Proved 6 – – – 31 – 37
– Unproved 305 39 – 93 1 2 440
Exploration costs 195 621 411 425 405 157 2,214
Development costs 6,774 3,764 1,439 3,149 3,068 1,002 19,196
Total costs incurred for consolidated subsidiaries 7,280 4,424 1,850 3,667 3,505 1,161 21,887
Equity Companies
Property acquisition costs – Proved – – – – – – –
– Unproved – – – – – – –
Exploration costs 9 – 41 – (19) – 31
Development costs 411 – 143 – 879 – 1,433
Total costs incurred for equity companies 420 – 184 – 860 – 1,464
108
Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2015, 2016,
and 2017.
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 flow.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to
the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or
production data or (3) changes in 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 that we report 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 2017 that were associated with production sharing
contract arrangements was 12 percent of liquids, 10 percent of natural gas and 11 percent on an oil-equivalent basis (natural gas
converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment
and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net
proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion.
Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s
oil and 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 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, include 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.
109
Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves
Natural Gas
Crude Oil Liquids (1) 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, 2015 2,108 282 199 1,102 2,132 141 5,964 1,092 4,233 534 11,823
Revisions (150) (10) 46 48 123 (4) 53 (95) 433 68 459
Improved recovery – – 2 – – – 2 – – – 2
Purchases 161 3 1 – – – 165 46 – – 211
Sales (9) – (1) – (2) – (12) (1) – – (13)
Extensions/discoveries 387 2 – – 698 – 1,087 101 – – 1,188
Production (119) (17) (63) (187) (126) (12) (524) (65) (106) (21) (716)
December 31, 2015 2,378 260 184 963 2,825 125 6,735 1,078 4,560 581 12,954
Proportional interest in proved
reserves of equity companies
January 1, 2015 328 – 27 – 1,100 – 1,455 435 – – 1,890
Revisions (52) – (1) – 65 – 12 5 – – 17
Improved recovery – – – – – – – – – – –
Purchases – – – – – – – – – – –
Sales – – – – – – – – – – –
Extensions/discoveries – – – – – – – – – – –
Production (22) – (1) – (88) – (111) (26) – – (137)
December 31, 2015 254 – 25 – 1,077 – 1,356 414 – – 1,770
Total liquids proved reserves
at December 31, 2015 2,632 260 209 963 3,902 125 8,091 1,492 4,560 581 14,724
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
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
(See footnote on next page)
110
Crude Oil, Natural Gas Liquids, Bitumen and Synthetic Oil Proved Reserves (continued)
Natural Gas
Crude Oil Liquids (1) 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, 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
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
(1) Includes total proved reserves attributable to Imperial Oil Limited of 7 million barrels in 2015, 7 million barrels in 2016 and
10 million barrels in 2017, as well as proved developed reserves of 4 million barrels in 2015, 4 million barrels in 2016 and
3 million barrels in 2017, and in addition, proved undeveloped reserves of 3 million barrels in 2015, 3 million barrels in 2016
and 7 million barrels in 2017, in which there is a 30.4 percent noncontrolling interest.
111
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 Amer. (1) Europe Africa Asia Oceania Total Amer. (2) Amer. (3) Total
(millions of barrels)
Proved developed reserves, as of
December 31, 2015
Consolidated subsidiaries 1,427 101 192 900 1,707 107 4,434 4,108 581 9,123
Equity companies 228 – 25 – 1,151 – 1,404 – – 1,404
Proved undeveloped reserves, as of
December 31, 2015
Consolidated subsidiaries 1,619 174 34 230 1,239 83 3,379 452 – 3,831
Equity companies 39 – – – 327 – 366 – – 366
Total liquids proved reserves at
December 31, 2015 3,313 275 251 1,130 4,424 190 9,583 4,560 581 14,724
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 (4) 1,012 473 12,029
(1) Includes total proved reserves attributable to Imperial Oil Limited of 34 million barrels in 2015, 35 million barrels in 2016
and 45 million barrels in 2017, as well as proved developed reserves of 23 million barrels in 2015, 19 million barrels in 2016
and 10 million barrels in 2017, and in addition, proved undeveloped reserves of 11 million barrels in 2015, 16 million barrels
in 2016 and 35 million barrels in 2017, in which there is a 30.4 percent noncontrolling interest.
(2) Includes total proved reserves attributable to Imperial Oil Limited of 3,515 million barrels in 2015, 701 million barrels in
2016 and 946 million barrels in 2017, as well as proved developed reserves of 3,063 million barrels in 2015, 436 million
barrels in 2016 and 591 million barrels in 2017, and in addition, proved undeveloped reserves of 452 million barrels in 2015,
265 million barrels in 2016 and 355 million barrels in 2017, in which there is a 30.4 percent noncontrolling interest.
(3) Includes total proved reserves attributable to Imperial Oil Limited of 581 million barrels in 2015, 564 million barrels in 2016
and 473 million barrels in 2017, as well as proved developed reserves of 581 million barrels in 2015, 564 million barrels in
2016 and 473 million barrels in 2017, in which there is a 30.4 percent noncontrolling interest.
(4) See previous pages for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For
additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2017 Form 10-K.
112
Natural Gas and Oil-Equivalent Proved Reserves
Natural Gas
Canada/ Oil-Equivalent
United Other Australia/ Total
States Amer. (1) Europe Africa Asia Oceania Total All Products (2)
(billions of cubic feet) (millions of oil-
equivalent barrels)
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 2015 25,987 1,226 2,383 811 5,460 7,276 43,143 19,013
Revisions (6,693) (45) 63 25 303 23 (6,324) (595)
Improved recovery – – – – – – – 2
Purchases 182 29 – – – – 211 246
Sales (9) (5) (56) – (89) – (159) (39)
Extensions/discoveries 1,167 34 – – 102 – 1,303 1,405
Production (1,254) (112) (434) (43) (447) (258) (2,548) (1,140)
December 31, 2015 19,380 1,127 1,956 793 5,329 7,041 35,626 18,892
Proportional interest in proved reserves
of equity companies
January 1, 2015 272 – 8,418 – 17,505 – 26,195 6,256
Revisions (38) – (83) – 86 – (35) 11
Improved recovery – – – – – – – –
Purchases 1 – – – – – 1 –
Sales – – – – – – – –
Extensions/discoveries – – – – – – – –
Production (15) – (432) – (1,130) – (1,577) (400)
December 31, 2015 220 – 7,903 – 16,461 – 24,584 5,867
Total proved reserves at December 31, 2015 19,600 1,127 9,859 793 21,790 7,041 60,210 24,759
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
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
(See footnotes on next page)
113
Natural Gas and Oil-Equivalent Proved Reserves (continued)
Natural Gas
Canada/ Oil-Equivalent
United Other Australia/ Total
States Amer. (1) Europe Africa Asia Oceania Total All Products (2)
(billions of cubic feet) (millions of oil-
equivalent barrels)
Net proved developed and undeveloped
reserves of consolidated subsidiaries
January 1, 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
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) Includes total proved reserves attributable to Imperial Oil Limited of 583 billion cubic feet in 2015, 495 billion cubic feet in
2016 and 641 billion cubic feet in 2017, as well as proved developed reserves of 283 billion cubic feet in 2015, 263 billion
cubic feet in 2016 and 282 billion cubic feet in 2017, and in addition, proved undeveloped reserves of 300 billion cubic feet in
2015, 232 billion cubic feet in 2016 and 359 billion cubic feet in 2017, in which there is a 30.4 percent noncontrolling interest.
(2) Natural gas is converted to oil-equivalent basis at six million cubic feet per one thousand barrels.
114
Natural Gas and Oil-Equivalent Proved Reserves (continued)
Natural Gas
Canada/ Oil-Equivalent
United Other Australia/ Total
States Amer. (1) Europe Africa Asia Oceania Total All Products (2)
(billions of cubic feet) (millions of oil-
equivalent barrels)
Proved developed reserves, as of
December 31, 2015
Consolidated subsidiaries 13,353 552 1,593 750 4,917 1,962 23,127 12,977
Equity companies 156 – 6,146 – 15,233 – 21,535 4,993
Proved undeveloped reserves, as of
December 31, 2015
Consolidated subsidiaries 6,027 575 363 43 412 5,079 12,499 5,915
Equity companies 64 – 1,757 – 1,228 – 3,049 874
Total proved reserves at December 31, 2015 19,600 1,127 9,859 793 21,790 7,041 60,210 24,759
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
(See footnotes on previous page)
115
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, 2015
Future cash inflows from sales of oil and gas 144,910 176,452 23,330 57,702 156,378 29,535 588,307
Future production costs 82,678 115,285 8,735 17,114 50,745 8,889 283,446
Future development costs 35,016 36,923 11,332 11,170 15,371 8,237 118,049
Future income tax expenses 5,950 3,042 1,780 14,018 62,353 5,012 92,155
Future net cash flows 21,266 21,202 1,483 15,400 27,909 7,397 94,657
Effect of discounting net cash flows at 10% 13,336 13,415 (945) 5,226 17,396 3,454 51,882
Discounted future net cash flows 7,930 7,787 2,428 10,174 10,513 3,943 42,775
Equity Companies
As of December 31, 2015
Future cash inflows from sales of oil and gas 13,065 – 49,061 – 143,692 – 205,818
Future production costs 6,137 – 35,409 – 57,080 – 98,626
Future development costs 2,903 – 2,190 – 12,796 – 17,889
Future income tax expenses – – 4,027 – 24,855 – 28,882
Future net cash flows 4,025 – 7,435 – 48,961 – 60,421
Effect of discounting net cash flows at 10% 1,936 – 4,287 – 26,171 – 32,394
Discounted future net cash flows 2,089 – 3,148 – 22,790 – 28,027
Total consolidated and equity interests in
standardized measure of discounted
future net cash flows 10,019 7,787 5,576 10,174 33,303 3,943 70,802
(1) Includes discounted future net cash flows attributable to Imperial Oil Limited of $5,607 million in 2015, in which there is a
30.4 percent noncontrolling interest.
116
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, 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
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
(1) Includes discounted future net cash flows attributable to Imperial Oil Limited of $2,322 million in 2016 and $3,344 million in
2017, in which there is a 30.4 percent noncontrolling interest.
117
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests 2015
Total
Share of Consolidated
Consolidated Equity Method and Equity
Subsidiaries Investees Interests
(millions of dollars)
Discounted future net cash flows as of December 31, 2014 138,664 68,921 207,585
Value of reserves added during the year due to extensions, discoveries,
improved recovery and net purchases less related costs 5,678 – 5,678
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of
production (lifting) costs (20,694) (9,492) (30,186)
Development costs incurred during the year 18,359 1,198 19,557
Net change in prices, lifting and development costs (203,224) (57,478) (260,702)
Revisions of previous reserves estimates 6,888 (134) 6,754
Accretion of discount 17,828 7,257 25,085
Net change in income taxes 79,276 17,755 97,031
Total change in the standardized measure during the year (95,889) (40,894) (136,783)
Discounted future net cash flows as of December 31, 2015 42,775 28,027 70,802
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.
118
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated and Equity Interests (continued) 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
OPERATING INFORMATION (unaudited)
119
2017 2016 2015 2014 2013
Production of crude oil, natural gas liquids, bitumen and synthetic oil
Net production (thousands of barrels daily)
United States 514 494 476 454 431
Canada/Other Americas 412 430 402 301 280
Europe 182 204 204 184 190
Africa 423 474 529 489 469
Asia 698 707 684 624 784
Australia/Oceania 54 56 50 59 48
Worldwide 2,283 2,365 2,345 2,111 2,202
Natural gas production available for sale
Net production (millions of cubic feet daily)
United States 2,936 3,078 3,147 3,404 3,545
Canada/Other Americas 218 239 261 310 354
Europe 1,948 2,173 2,286 2,816 3,251
Africa 5 7 5 4 6
Asia 3,794 3,743 4,139 4,099 4,329
Australia/Oceania 1,310 887 677 512 351
Worldwide 10,211 10,127 10,515 11,145 11,836
(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1) 3,985 4,053 4,097 3,969 4,175
Refinery throughput (thousands of barrels daily)
United States 1,508 1,591 1,709 1,809 1,819
Canada 383 363 386 394 426
Europe 1,510 1,417 1,496 1,454 1,400
Asia Pacific 690 708 647 628 779
Other Non-U.S. 200 190 194 191 161
Worldwide 4,291 4,269 4,432 4,476 4,585
Petroleum product sales (2)
United States 2,190 2,250 2,521 2,655 2,609
Canada 499 491 488 496 464
Europe 1,597 1,519 1,542 1,555 1,497
Asia Pacific and other Eastern Hemisphere 1,164 1,140 1,124 1,085 1,206
Latin America 80 82 79 84 111
Worldwide 5,530 5,482 5,754 5,875 5,887
Gasoline, naphthas 2,262 2,270 2,363 2,452 2,418
Heating oils, kerosene, diesel oils 1,850 1,772 1,924 1,912 1,838
Aviation fuels 382 399 413 423 462
Heavy fuels 371 370 377 390 431
Specialty petroleum products 665 671 677 698 738
Worldwide 5,530 5,482 5,754 5,875 5,887
Chemical prime product sales (2) (thousands of metric tons)
United States 9,307 9,576 9,664 9,528 9,679
Non-U.S. 16,113 15,349 15,049 14,707 14,384
Worldwide 25,420 24,925 24,713 24,235 24,063
Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas,
petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage and refining throughput includes
quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment
is made in kind or cash.
(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Petroleum product and chemical prime product sales data reported net of purchases/sales contracts with the same
counterparty.
INDEX TO EXHIBITS
120
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.*
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 (incorporated by reference to Exhibit 10(iii)(b.1) to the Registrant’s Annual
Report on Form 10-K for 2013).*
10(iii)(b.2) Earnings Bonus Unit instrument.*
10(iii)(c.1) ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 10(iii)(c.1) to the Registrant’s 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 (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Annual
Report on Form 10-K for 2013).*
10(iii)(d) ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the
Registrant’s Annual Report on Form 10-K for 2016).*
10(iii)(f.1) 2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s
Annual Report on Form 10-K for 2013).*
10(iii)(f.2) Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference
to Exhibit 10(iii)(f.2) to the Registrant’s 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).*
12 Computation of ratio of earnings to fixed charges.
14 Code of Ethics and Business Conduct.
18 Preferability Letter of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
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.
121
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 28, 2018
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Beth E. Casteel, Stephen A. Littleton, 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 28, 2018.
/s/ DARREN W. WOODS
(Darren W. Woods)
Chairman of the Board
(Principal Executive Officer)
/s/ SUSAN K. AVERY
(Susan K. Avery)
Director
/s/ MICHAEL J. BOSKIN
(Michael J. Boskin)
Director
/s/ ANGELA F. BRALY
(Angela F. Braly)
Director
/s/ URSULA M. BURNS
(Ursula M. Burns)
Director
122
/s/ KENNETH C. FRAZIER
(Kenneth C. Frazier)
Director
/s/ STEVEN A. KANDARIAN
(Steven A. Kandarian)
Director
/s/ DOUGLAS R. OBERHELMAN
(Douglas R. Oberhelman)
Director
/s/ SAMUEL J. PALMISANO
(Samuel J. Palmisano)
Director
/s/ STEVEN S REINEMUND
(Steven S Reinemund)
Director
/s/ WILLIAM C. WELDON
(William C. Weldon)
Director
/s/ ANDREW P. SWIGER
(Andrew P. Swiger)
Senior Vice President
(Principal Financial Officer)
/s/ DAVID S. ROSENTHAL
(David S. Rosenthal)
Vice President and Controller
(Principal Accounting Officer)
EXHIBIT 12
EXXON MOBIL CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
2017 2016 2015 2014 2013
(millions of dollars)
Income from continuing operations attributable to ExxonMobil 19,710 7,840 16,150 32,520 32,580
Excess/(shortfall) of dividends over earnings of affiliates
accounted for by the equity method 131 (579) (691) (358) 3
Provision for income taxes (1,174) (406) 5,415 18,015 24,263
Capitalized interest (252) (224) (7) 121 148
Noncontrolling interests in earnings of consolidated subsidiaries 138 535 401 1,095 868
18,553 7,166 21,268 51,393 57,862
Fixed Charges:
Interest expense – borrowings 465 390 211 157 137
Capitalized interest 749 708 482 344 309
Rental cost representative of interest factor 303 433 585 618 612
1,517 1,531 1,278 1,119 1,058
Total adjusted earnings available for payment of fixed charges 20,070 8,697 22,546 52,512 58,920
Number of times fixed charges are earned 13.2 5.7 17.6 46.9 55.7
EXHIBIT 18
February 28, 2018
Board of Directors
Exxon Mobil Corporation
5959 Las Colinas Boulevard
Irving, Texas 75039
Dear Directors:
We are providing this letter to you for inclusion as an exhibit to Exxon Mobil Corporation’s (the “Corporation”) Annual Report
on Form 10-K for the year ended December 31, 2017 (the “Form 10-K”) pursuant to Item 601 of Regulation S-K.
We have audited the consolidated financial statements included in the Form 10-K and issued our report thereon dated
February 28, 2018. Note 2 “Accounting Changes” to the financial statements describes a change in accounting principle related
to the reporting of certain sales and value-added taxes imposed on and concurrent with revenue-producing transactions with
customers and collected on behalf of governmental authorities (“Sales-based taxes”) from gross reporting of Sales-based taxes on
the Consolidated Statement of Income (included in both “Sales and other operating revenue” and “Sales-based taxes”) to net
reporting (excluded from both “Sales and other operating revenue” and “Sales-based taxes”). It should be understood that the
preferability of one acceptable method of accounting over another for Sales-based taxes has not been addressed in any
authoritative accounting literature, and in expressing our concurrence below we have relied on management’s determination that
this change in accounting principle is preferable. Based on our reading of management’s stated reasons and justification for this
change in accounting principle in the Form 10-K, and our discussions with management as to their judgment about the relevant
business planning factors relating to the change, we concur with management that such change represents, in the Corporation’s
circumstances, the adoption of a preferable accounting principle in conformity with Accounting Standards Codification 250,
Accounting Changes and Error Corrections.
Very truly yours,
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
EXHIBIT 31.1
Certification by Darren W. Woods
Pursuant to Securities Exchange Act Rule 13a-14(a)
I, Darren W. Woods, certify that:
1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: February 28, 2018
/s/ DARREN W. WOODS
Darren W. Woods
Chief Executive Officer
EXHIBIT 31.2
Certification by Andrew P. Swiger
Pursuant to Securities Exchange Act Rule 13a-14(a)
I, Andrew P. Swiger, certify that:
1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: February 28, 2018
/s/ ANDREW P. SWIGER
Andrew P. Swiger
Senior Vice President
(Principal Financial Officer)
EXHIBIT 31.3
Certification by David S. Rosenthal
Pursuant to Securities Exchange Act Rule 13a-14(a)
I, David S. Rosenthal, certify that:
1. I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in
all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is
being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;
and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: February 28, 2018
/s/ DAVID S. ROSENTHAL
David S. Rosenthal
Vice President and Controller
(Principal Accounting Officer)
EXHIBIT 32.1
Certification of Periodic Financial Report
Pursuant to 18 U.S.C. Section 1350
For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned,
Darren W. Woods, the chief executive officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:
(i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2017, as filed with the Securities and
Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations
of the Company.
Date: February 28, 2018
/s/ DARREN W. WOODS
Darren W. Woods
Chief Executive Officer
A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be
retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 32.2
Certification of Periodic Financial Report
Pursuant to 18 U.S.C. Section 1350
For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned,
Andrew P. Swiger, the principal financial officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his
knowledge:
(i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2017, as filed with the Securities and
Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations
of the Company.
Date: February 28, 2018
/s/ ANDREW P. SWIGER
Andrew P. Swiger
Senior Vice President
(Principal Financial Officer)
A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be
retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 32.3
Certification of Periodic Financial Report
Pursuant to 18 U.S.C. Section 1350
For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned,
David S. Rosenthal, the principal accounting officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his
knowledge:
(i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2017, as filed with the Securities and
Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations
of the Company.
Date: February 28, 2018
/s/ DAVID S. ROSENTHAL
David S. Rosenthal
Vice President and Controller
(Principal Accounting Officer)
A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be
retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
FORM 10-K
PART I
ITEM 1. BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERMATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENTAND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 16. FORM 10-K SUMMARY
FINANCIAL SECTION
TABLE OF CONTENTS
BUSINESS PROFILE
FINANCIAL INFORMATION
FREQUENTLY USED TERMS
QUARTERLY INFORMATION
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS
FORWARD-LOOKING STATEMENTS
OVERVIEW
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
REVIEW OF 2017 AND 2016 RESULTS
LIQUIDITY AND CAPITAL RESOURCES
CAPITAL AND EXPLORATION EXPENDITURES
TAXES
ENVIRONMENTAL MATTERS
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
RECENTLY ISSUED ACCOUNTING STANDARDS
CRITICAL ACCOUNTING ESTIMATES
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEET
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Accounting Policies
2. Accounting Changes
3. Miscellaneous Financial Information
4. Other Comprehensive Income Information
5. Cash Flow Information
6. Additional Working Capital Information
7. Equity Company Information
8. Investments, Advances and Long-Term Receivables
9. Property, Plant and Equipment and Asset Retirement Obligations
10. Accounting for Suspended Exploratory Well Costs
11. Leased Facilities
12. Earnings Per Share
13. Financial Instruments and Derivatives
14. Long-Term Debt
15. Incentive Program
16. Litigation and Other Contingencies
17. Pension and Other Postretirement Benefits
18. Disclosures about Segments and Related Information
19. Income and Other Taxes
20. Acquisitions
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
OPERATING INFORMATION
EXHIBIT 12
EXHIBIT 18
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 31.3
EXHIBIT 32.1
EXHIBIT 32.2
EXHIBIT 32.3
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