EXXON MOBIL CORP - DEF 14A - 20080410 - PROPOSAL_3
ITEM 13 – COMMUNITY ENVIRONMENTAL IMPACT
This proposal was submitted by The Episcopal Church, 815 Second Avenue, New York, NY
10017, as lead proponent of a filing group.
“
Resolved
:
Shareholders
request that the Board of Directors report, at reasonable cost and omitting proprietary information, on how the corporation ensures that it is accountable for its environmental impacts in all of the communities where it operates. The report should
contain the following information:
1.
how the corporation makes available reports regarding its emissions and environmental impacts on land, water, and soil – both within its permits and emergency emissions – to members
of the communities where it operates;
2.
how the corporation integrates community environmental accountability into its current code of conduct and ongoing business practices; and
3.
the extent to which the corporation’s activities have negative health effects on individuals living in economically-poor communities.
Supporting statement
ExxonMobil ranks 6
th
on a list of worst U.S. corporate polluters in terms of the amount and toxicity of pollution, and the numbers of people exposed to it
(based on 2002 toxics data).
http://www.peri.umass.edu/Toxic-100-Table.265.0.html
Most of this pollution is from ExxonMobil’s refinery operations.
ExxonMobil’s refinery in Baton Rouge, LA, is the second largest emitter of toxic pollutants among all U.S. EPA regulated refineries. Its Joliet, IL, refinery is the largest source of toxic air and water emissions in that state.
ExxonMobil has come under scrutiny for a January 2006 release of process gas from its Baytown, TX, refinery (
Houston Chronicle
3/26/06) and for lax security at its
Chalmette, LA, refinery where enough hydrofluoric acid is stored to put the population of New Orleans at risk. (
NY Times
5/22/05)
In October 2005, ExxonMobil
agreed to pay $571 million to install pollution control technologies at seven of its refineries in settlement of EPA claims of federal Clean Air Act violations. ExxonMobil was also required to pay $8.7 in fines and $9.7 million on supplemental
environmental projects.
Refineries account for 5 percent of the country’s dangerous air pollution. As a former EPA official explained, refinery pollution
affects local communities more than power plants because it is released from short smokestacks and does not dissipate readily. ‘People are living cheek by jowl with refinery pollution.’ (Washington Post 1/28/05)
http://www.washingtonpost.com/wp-dyn/articles/A43014-005Jan27.html?referrer=email
Corporations have a moral responsibility to be accountable for their
environmental impacts – not just effects on the entire ecosystem, but also direct effects on the communities that host their facilities. Communities are often the forgotten stakeholders in terms of corporate activities and impact. No
corporation can operate without the resources that local communities provide, but it is often these communities that bear the brunt of corporate activities.
Also of
concern to proponents are the effects of corporate activities on low-income areas and communities of color. Several of the ‘fence-line communities’ near ExxonMobil’s refineries are African American. One study has found that facilities
like oil refineries operated in largely African-American counties may ‘pose greater risk of accident and injury than those in counties with fewer African-Americans.’
Environmental Justice: Frequency and Severity of U.S. Chemical
Industry Accidents and the
Socio-economic Status of Surrounding Communities,
58 Journal of Epidemiology and Community Health, 24-30 (2004).”
The Board recommends you vote AGAINST this proposal for the following reasons:
ExxonMobil is committed to operating in an environmentally responsible manner in every place we do business. The Corporation communicates with shareholders and the public about our environmental performance through the
Corporate
Citizenship Report
(
CCR
), national reporting systems, and site-based communication processes. The Board believes the additional report requested by this proposal would be duplicative to information already available to the public.
ExxonMobil’s Environmental Policy clearly states the Company will comply with all applicable laws and regulations and apply responsible standards where laws do
not exist. Assessments of performance are conducted at each site via the Operations Integrity Management System, which includes environmental performance expectations and is fully compliant with the International Organization for
Standardization’s standard for environmental management systems (ISO 14001).
ExxonMobil has had detailed guidelines in place since 1998 for the assessment of
environmental aspects and mitigation of potential impacts. In 2007, the Company revised this Environmental Aspects Guideline to enable more comprehensive identification and risk-based assessments of environmental impacts. These assessments provide
input to our Environmental Business Plans, which are utilized by all sites to systematically identify key environmental drivers, set targets in key focus areas, and identify projects and actions to achieve those targets.
For example, we have reduced our air emissions such as sulfur dioxide, nitrogen oxides (NOx), and volatile organic compounds (VOC) by 11 to 20 percent from 2003 to 2006. In
addition, since the launch of our Global Energy Management System in 2000, we have identified opportunities to improve energy efficiency of our refineries and chemical plants by 15 to 20 percent. More than 50 percent of these opportunities have been
captured. For example, through actions taken in 2006 and 2007 we reduced GHG emissions by about 5 million metric tons in 2007, equivalent to removing about one million cars from U.S. roads. In 2007, our Baton Rouge Refinery was presented the
EnergyStar Award by the U.S. Environmental Protection Agency in recognition of the facility’s industry-leading improvements in energy efficient operations. This refinery has reduced VOCs by 72 percent and NOx by 31 percent compared to 1990, and
reduced flaring by 69 percent compared to 2004.
An integral step in assessing and mitigating potential environmental impacts is the ability to accurately monitor
emissions. ExxonMobil has been active in the development and application of Leak Detection and Repair, and air and water monitoring technologies enabling significant reductions in fugitive emissions across our operations, such as the 72-percent
reduction in fugitive emissions from equipment at the Baton Rouge Refinery since 2000.
ExxonMobil is committed to ongoing engagement with communities in which we
operate. The Corporation has implemented globally Best Practices in External Affairs (BPEA), our primary management system for external affairs. BPEA is a strategic planning and management tool that teaches and encourages ExxonMobil affiliates to
seek and practice excellence in community relationships at every level. During the life of a project or facility, we meet regularly with community leaders, community associations, and nongovernmental organizations that are interested in our
operations. This helps us better understand the viewpoints and concerns of the diverse communities in which we operate, and provides us with an opportunity to share information on operational processes, environmental safeguards, and future plans. At
many sites, these relationships have been formalized through Citizen Advisory Panels that meet routinely with facility management.
Through the
CCR
, available
on our Web site at
exxonmobil.com/citizenship
, the Company reports on key Environmental Performance Indicators consistent with the published International Petroleum Industry Environmental Conservation Association Guidelines, including air
emissions, spills, and hydrocarbon to water. The Company participates in numerous publicly available national reporting systems, such as the European Pollutant Emission Register, U.S. Toxics Release Inventory, and Japanese Pollutant Release and
Transfer Register. Further, many of our affiliates and operating facilities produce citizenship reports or community newsletters to communicate site-specific
information locally.
ExxonMobil has donated over $100 million to community and social development programs, and over $75 million to health and environmental programs
since 2000. The Company supports research to understand the impacts of air quality on health including support for the Mickey Leland National Air Toxics Research Center and The National Environmental Respiratory Center.
ITEM 14 – ANWR DRILLING REPORT
This proposal was submitted by Green Century Capital Management, 114 State Street, Suite 200,
Boston, MA 02109, as lead proponent of a filing group.
“WHEREAS: the Arctic National Wildlife Refuge is the only conservation area in the nation that provides a
complete range of Arctic and sub-Arctic ecosystems balanced with a wide variety of wildlife, including large populations of caribou, musk oxen, polar bears, snow geese and 180 species of other migratory birds;
The U.S. Fish and Wildlife Service considers the Arctic Refuge one of the finest examples of wilderness left on the planet;
The coastal plain of the Arctic Refuge is the only section of Alaska’s entire North Slope not open for oil and gas leasing, exploration and production;
RESOLVED, the Shareholders request that Board of Directors prepare a report, at reasonable cost and omitting proprietary information, on the potential environmental damage that
would result from the company drilling for oil and gas in the coastal plain of the Arctic National Wildlife Refuge. The report should consider the implications of a policy of refraining from drilling in this area.
Supporting Statement
‘Ninety-five percent of Alaska’s most promising
oil-bearing lands are already open for development, but it is imperative that we continue to protect the wildlife, fish and wilderness that make up the rest of this invaluable part of our American heritage.’ – President Jimmy Carter (1995)
Once part of the largest intact wilderness area in the United States, the North Slope now hosts one of the world’s largest industrial complexes. In fact, oil
companies already have access to an overwhelming majority of Alaska’s North Slope. More than 1500 miles of roads and pipelines and thousands of acres of industrial facilities sprawl over some 400 square miles of once pristine arctic tundra. Oil
operations on the North Slope annually emit roughly 43,000 tons of nitrogen oxides and 100,000 metric tons of methane, emissions that contribute to smog, acid rain, and global warming.
The coastal plain is the biological heart of the Refuge, to which the vast Porcupine River caribou herd migrates each spring to give birth. The Department of Interior has concluded that development in the coastal plain would
result in major adverse impacts on the caribou population. According to biologists from the Alaska Department of Fish and Game caribou inhabiting the oil fields do not thrive as well as members of the same herd that seldom encounter oil-related
facilities.
The coastal plain is also the most important onshore denning area for the entire South Beaufort Sea polar bear population, and serves as crucial habitat
for musk oxen and for at least 180 bird species that gather there for breeding, nesting and migratory activities.
Balanced against these priceless resources is the
small potential for economically recoverable oil in the coastal plain. In fact, the most recent federal estimate predicted that only 3.2 billion barrels would be economically recoverable in the coastal plain – less than 6 months worth of oil
for the United States.
Vote YES for this proposal, which will improve our Company’s reputation as a leader in environmentally responsible energy recovery.”
The Board recommends you vote AGAINST this proposal for the following reasons:
This proposal is essentially the same as proposals submitted for the ExxonMobil annual meetings in 2000, 2001, and 2002. More than 90 percent of the votes cast by shareholders in
these years were AGAINST this proposal. Given the uncertainties about timing and content of potential changes in the federal regulations prohibiting Arctic National Wildlife Refuge (ANWR) development, the Board believes preparation of a report on a
hypothetical drilling program would be a waste of Company resources.
Oil and gas exploration and development in ANWR is currently prohibited by federal regulations.
ANWR encompasses 19 million acres, of which the Coastal Plain is about 1.5 million acres. The U.S. Department of Interior estimates the Coastal Plain could contain between 9 and 16 billion barrels of recoverable oil. ExxonMobil has no
property interests or rights to acquire property interests or drilling rights in the Coastal Plain. However, if the federal government chose to allow exploration and development, the Company might pursue those opportunities.
ExxonMobil supports environmentally responsible exploration and development within the Coastal Plain of ANWR. Technological and environmental protection developments across the
industry have demonstrated the ability to develop oil and gas reserves in environmentally sensitive areas by minimizing surface disruption and facilities, and implementing reasonable protection measures. ExxonMobil’s Sakhalin development in
eastern Russia is an example of this ability.
ExxonMobil has Environmental Aspects Guidelines in place to enable comprehensive identification and risk-based
assessment of potential environmental impacts. These assessments provide input to our Environmental Business Planning processes which systematically identify key environmental drivers, set targets in key focus areas, and identify projects and
actions to achieve those targets.
ITEM 15 – GREENHOUSE GAS EMISSIONS GOALS
This proposal was submitted by the Sisters of St. Dominic of Caldwell New Jersey, 40
South Fullerton Avenue, Montclair, NJ 07042, as lead proponent of a filing group.
“WHEREAS:
The International Energy Agency warned in its 2007 World Energy Outlook that ‘urgent action is needed if greenhouse gas [GHG] concentrations are to be stabilized at a level that would prevent dangerous interference with
the climate system.’
ExxonMobil operates in countries that have ratified the Kyoto Protocol, obliging them to reduce GHG emissions below 1990 levels by 2012.
Yet Kyoto targets may be inadequate to avert the most serious impacts of global warming. Dozens of companies, including competitors ConocoPhillips, BP America, and Shell, have endorsed calls for the US to reduce carbon emissions by 60-80% by 2050.
150 global corporations have called on world leaders to finalize a comprehensive, binding UN framework to tackle climate change, urging already industrialized nations to make the greatest efforts (11/30/07).
ExxonMobil has minimally invested in cogeneration, improved energy efficiency in refineries, reduced gas flaring, and supported climate research. For five years, ExxonMobil has
stressed its donation to Stanford University’s Global Climate and Energy Project, and its partnerships with Toyota and Caterpillar on advanced fuels and engines, yet shareholders are given little information on progress or outcomes regarding
these initiatives.
ExxonMobil has identified opportunities to increase operational energy efficiency by 15-20%, yet has implemented only half of these, missing
potential savings of $750 million per year (
Carbon Disclosure Project 5
). ExxonMobil’s global energy costs for 2006 totaled $10 billion, equal to 1,475 trillion BTUs of energy.
Despite its well-publicized efforts, ExxonMobil’s global CO
2
emissions increased from 2003 to 2006 –
absolute operational emissions were 145.5 million metric tons in 2006, a 5.4% increase since 2005 (
CDP5
).
BP, Shell, ConocoPhillips, and Chevron each have significant commitments to investments in renewables, low-carbon technologies to
reduce emissions, integration of the cost of carbon into strategic planning and investments, and compensation incentives for climate performance. These commitments have already enabled competitors to: secure positions in specific alternative energy
markets, deliver emissions reductions, prepare for regulatory requirements, and raise their credibility in public policy debates.
Shifts in consumer preference,
coupled with emissions regulations and sustained high oil prices, could significantly alter ExxonMobil’s market assumptions for the next 30 years. A March 2007 Credit Suisse report notes: ‘An increase in the efficiency of energy
consumption and in the amount of renewable electricity production will likely lower long-term future demand growth for both oil and gas relative to current expectations.’
Proponents are concerned that ExxonMobil’s business plan appears to consider few scenarios that incorporate a decline in these markets due to forthcoming regulations and incentives, or governments’ need to stabilize
global GHG emissions because of the physical risks they pose.
THEREFORE, BE IT RESOLVED:
shareholders request that the Board of Directors adopt quantitative
goals, based on current technologies, for reducing total greenhouse gas emissions from the Company’s products and operations; and that the Company report to shareholders by September 30, 2008, on its plans to achieve these goals. Such a
report will omit proprietary information and be prepared at reasonable cost.”
The Board recommends you vote AGAINST this proposal for the following reasons:
At ExxonMobil, we take the risk posed by rising greenhouse gas (GHG) emissions seriously and are taking action. Our views, actions, and progress on climate
change are widely available, for example, in executive speeches, in the report
Tomorrow’s Energy: A Perspective on Energy Trends, Greenhouse Gas Emissions and Future Energy Options
(2006), in our report to the
Carbon Disclosure
Project
(2007), and in the annual
Corporate Citizenship Report
. While investing to increase production, our scientists and engineers are diligently seeking opportunities to improve efficiency and reduce emissions while maintaining
leadership in returns to shareholders. As well, the Company will comply with emerging laws and regulations concerning GHG emissions.
In pursuing its business
objectives on behalf of shareholders and in meeting society’s aspirations for a better future, ExxonMobil seeks to increase oil and natural gas production to meet rising global demand. The primary opportunities for reducing greenhouse gas
emissions from the Company’s operations are in improving energy efficiency and in reducing flaring. In both areas, the Company’s operations have improvement objectives and planned improvement steps that will offset some of the growth
associated with higher production and more energy-intensive operations. For example, through actions taken in 2006 and 2007, we reduced GHG emissions by about 5 million metric tons in 2007, equivalent to removing about one million cars from
U.S. roads. In Nigeria, we are investing about $3 billion on projects to effectively eliminate routine gas flaring in our operations there. In addition, as part of the American Petroleum Institute’s Climate Change Program, ExxonMobil committed
to improve energy efficiency by 10 percent between 2002 and 2012 across U.S. refining operations. We are on pace to exceed that commitment, not only in the U.S., but globally as well.
GHG emissions from ExxonMobil’s customers’ use of its products are determined both by the need for energy and by the efficiency with which the energy is consumed. The Company has active research efforts under way to
identify technologies that can improve the efficiency of the use of its products. For example, in the past year, ExxonMobil announced the development of a new technology for on-board hydrogen reforming to power fuel cell vehicles, as well as the
deployment of new battery separator films for use in lithium-ion batteries in hybrid and electric vehicles. Both of these technologies demonstrate significant potential to reduce emissions from transport.
Besides efficiency gains, another step to reduce GHG emissions involves more widespread use of natural gas, rather than coal, to produce electric power – an area in which
ExxonMobil is well-positioned to enhance supplies. Another means to reduce GHG emissions is carbon capture and storage. We have
been involved in the development and utilization of this technology in our own oil and gas operations and in partnership with others for over three decades. In 2006,
we agreed to participate in a ground-breaking research initiative sponsored by the European Commission called “CO
2
ReMoVe” to establish scientific monitoring standards
and determine the reliability of geological CO
2
storage.
Beyond efforts to reduce emissions
from our own operations and products, ExxonMobil has also worked to establish and is providing $100 million to Stanford University’s long-term Global Climate and Energy Project (GCEP). GCEP is a pioneering research effort aimed at innovation
across a broad portfolio of technology areas that can lower GHG emissions on a worldwide scale. Results and progress are available on the GCEP Web site.
ITEM 16 – CO
2
INFORMATION AT THE PUMP
This proposal was
submitted by Mr. Mario Lalanne, 19 chemin de Casson, Westmount, Quebec, Canada H3Y 2G9.
“Resolved that Exxon Mobil Corporation inform its customers about
the carbon dioxide (CO
2
) emissions generated by the gasoline or the diesel fuel they buy. The quantitative information would be provided at the pump and based on average
well-to-wheels figures, i. e. encompassing all phases from extraction up to and including consumption.
SUPPORTING STATEMENT:
Ÿ
Concerns about greenhouse gases, especially carbon dioxide (CO
2
), are rising fast. Yet, where millions
of daily transactions take place, there is no perceptible effort from the oil industry to disseminate facts and figures relative to CO
2
emissions, be it on the bills, the
receipts, or any suitable sign visible at the service point. It would be timely for ExxonMobil, the world’s largest publicly traded international oil and gas company, to develop and systematically provide consumer-friendly information about CO
2
emissions.
Ÿ
Either ExxonMobil takes the leadership in this matter or there is a great risk that it will be forced by numerous governments to comply to many different, less consistent,
and less practical information requirements, because concerns about CO
2
emissions will not fade away. Shareholders would benefit from ExxonMobil’s decisiveness, but they
could suffer prejudice if this opportunity is missed.”
The Board recommends you vote AGAINST this proposal for the following reasons:
The Board does not believe that consumer labeling at the pump is an effective or appropriate way to address public concerns about climate change or individuals’
contributions to greenhouse gas emissions.
CO
2
emissions data from combustion of standard
fuels, such as gasoline or diesel, are well known, readily available, and widely disseminated from public sources. In our 2006
Corporate Citizenship Report,
ExxonMobil provided emissions data for gasoline and diesel. However, such information
does little to address the full range of issues that consumers might wish to consider to assess their contribution to greenhouse gas emissions and options to address them. These include consumers’ choice of vehicle and practices for commuting
and travel. As well, emissions arise from a variety of other choices that consumers make regarding place of residence, housing, appliances, and lifestyle.
ExxonMobil
supports and contributes to studies that evaluate the full range of emissions associated with the manufacture and use of petroleum and other fuels for various combinations of existing and advanced fuels and vehicles. Such well-to-wheel studies are
complex. In particular, they involve a wide range of inputs and assumptions regarding the original resource, such as crude oil, oil sands, corn, sugar cane, or other biomass; methods of production and refining; and options for vehicles and drive
trains. Emissions from well-to-wheels vary considerably – both from well-to-pump, depending on different resources and production options, and from pump-to-wheels, depending on vehicle choice and driving habits.
ExxonMobil provides a range of information on climate issues in various publications and speeches that are readily available on its Web site, particularly the report
Tomorrow’s Energy: A Perspective on Energy
Trends, Greenhouse Gas Emissions and Future Energy Options
(2006) and our annual
Energy Outlook.
In particular, ExxonMobil supports efforts to
improve energy efficiency and has provided information on actions that individuals can take through widely distributed opinion editorials.
ITEM 17 – CLIMATE CHANGE AND TECHNOLOGY REPORT
This proposal was submitted by Ms. Neva Rockefeller Goodwin, 30
Rockefeller Plaza, Room 5600, New York, NY 10112, as lead proponent of a filing group.
“Resolved:
Shareholders ask Exxon Mobil Corporation’s
(‘ExxonMobil’s’) Board of Directors to establish a task force, which should include both (a) two or more independent directors and (b) relevant company staff, to investigate and report to shareholders on the likely
consequences of global climate change between now and 2030, for emerging countries, and poor communities in these countries and developed countries, and to compare these outcomes with scenarios in which ExxonMobil takes leadership in developing
sustainable energy technologies that can be used by and for the benefit of those most threatened by climate change. The report should be prepared at reasonable expense, omitting proprietary information, and should be made available to shareholders
by March 31, 2009.
SUPPORTING STATEMENT
The April 2007
Fourth Assessment from the United Nation’s Intergovernmental Panel on Climate Change (Working Group II) details the potential climate-change-related devastation that regions like Africa and Asia will suffer. IPCC Chairman Rajendra Pachauri
noted that ‘It’s the poorest of the poor in the world, and this includes poor people even in prosperous societies, who are going to be the worst hit.’
This view is widely shared. As stated by The Prince Of Wales Corporate Leaders Group on Climate Change, an organization that
includes AIG, Dupont and GE, in a November 30
th
, 2007 Communique: ‘The economic and geopolitical costs of unabated climate change could be very severe and
globally disruptive. All countries and economies will be affected, but it will be the poorest countries that will suffer earliest and the most’. As witnessed by the destruction brought on by hurricane Katrina, extreme climate events can
devastate poor communities even in the United States.
ExxonMobil often argues that cheap and abundant energy is crucial for the economic advancement of poor
economies. These countries are forecast, by ExxonMobil and others, to contribute the largest increase in energy use. However, if, as predicted by ExxonMobil, this energy use is based on continued reliance on hydrocarbons, we will see an unrelenting
increase in global CO
2
emissions with devastating consequences especially for those who are poor in resources and influence, whether they live in the rich or the poor countries.
To the extent that ExxonMobil’s growth continues to rely on the sale of hydrocarbon energy to emerging markets, it faces a painful paradox in the future, and distances itself from its true legacy. Part of John D. Rockefeller’s genius was
in recognizing early on the need and opportunity of a transition to a better and cheaper fuel.
While investment in renewable energy sources and ‘clean’
technologies has recently accelerated, driven by players as diverse as venture capitalists, chemical companies, internet companies and old fashioned utilities, we believe our company is now lagging in creating solutions for the looming climate and
energy crisis. We are concerned that ExxonMobil’s current slow course in exploring and promoting low carbon or carbon-free energy technologies will exacerbate the crisis rather than make ExxonMobil part of the solution.
We urge shareholders to vote for this proposal.”
The Board recommends you vote AGAINST
this proposal for the following reasons:
The information requested in this proposal on possible climate impacts and on ExxonMobil’s views and actions on
global climate change are already widely available in existing publications that have been provided to the proponent. In addition, the proponent and colleagues have extensively corresponded with directors and management representatives and
personally have met with members of senior
management several times in recent years to review the Company’s climate change views and actions, and renewable energy technologies. Therefore, the Board does
not believe an additional report is warranted.
A number of third-party assessments of the impacts of climate change are publicly available, most notably the recently
published
Fourth Assessment Report of the Intergovernmental Panel on Climate Change
(IPCC, 2007), an effort in which ExxonMobil scientists directly
participate. The IPCC Report includes an entire, book-length volume on Impacts and Adaptation that discusses impacts and vulnerability of society and ecosystems to future climate change. In view of the comprehensive material available, there is no
need for an independent ExxonMobil report on climate impacts.
ExxonMobil’s views on future energy demand, greenhouse gas emissions, options to limit growth in
emissions, and ExxonMobil’s actions to address climate risks are available in several publications including:
Tomorrow’s Energy, Corporate Citizenship Report,
and our report to the
Carbon Disclosure Project
. These reports
discuss anticipated future trends and the potential for various policies and technologies to limit future emissions.
The cited publications and executive speeches
published on the ExxonMobil Web site also discuss ExxonMobil’s actions to reduce greenhouse gas emissions in its own operations and the steps we are taking to promote efficiency in the use of our products by customers. These actions include
both research and development to create viable options to address climate risks, and steps to commercialize advanced technologies that will reduce future emissions.
ITEM 18 – ENERGY TECHNOLOGY REPORT
This proposal was submitted by the Province of St. Joseph of the Capuchin Order, 1015
North Ninth Street, Milwaukee, WI 53233.
“
WHEREAS,
ExxonMobil’s (XOM) energy supply faces increasing complexities and difficulties. This sourcing
problem arises from various factors: a leveling of our oil supply in Non-OPEC nations, increasing volatility in OPEC nations, unilateral actions in countries like Venezuela who demand contract revisions, a lack of new refineries and old refineries
that must be shut down for repairs.
Given such problems, many call for ‘U.S. energy independence.’ In interviews and debates among Republican Presidential
candidates in 2007, John McCain envisioned the nation becoming ‘energy independent in five years.’ He called for a ‘Marshall Plan’ in this direction (12.12.07). He also noted a key obstacle toward this realization has been
‘special interests,’ including ‘petroleum companies’ (12.11.07). Another Republican candidate, Mike Huckabee, promised that, if elected, he would move the nation to become ‘oil free’ in our energy consumption in ten
years (12.11.07).
This resolution’s proponents believe that, ideally, in an interconnected and interdependent world, every nation should have sufficient food
and fuel to meet its basic needs, realized in ways that ensure sustainable development.
Among various options being considered that might move the U.S. toward energy
independence and sustainability sooner rather than later is engineered geothermal development. This has been suggested by the Massachusetts Institute of Technology, a major recipient of XOM monies, in its effort to address the issue of greenhouse
gas reduction and the promotion of alternative energy sources.
‘A comprehensive new MIT-led study of the potential for geothermal energy within the United
States has found that mining the huge amounts of heat that reside as stored thermal energy in the Earth’s hard rock crust could supply a substantial portion of the electricity the United States will need in the future, probably at competitive
prices and with minimal environmental impact… Just 2 percent of the U.S. geothermal resource base could yield nearly 2,000 times the power that the nation now consumes each year.’
http://web.mit.edu/newsoffice/2007/geothermal.html
Commenting on this dramatic development,
U.S. News and World Report
added that, since geothermal energy, unlike solar or wind, is constant, MIT said it could
provide 10% of U.S. base-load energy needs
[by 2050] if the nation would spend $1 billion on [jump-starting] its development over the next 15 years – less than the cost of one coal plant.
http://www.usnews.com/articles/business/economy/2007/10/26/power-revolution.htm?PageNr=3
Sherri K. Stuewer, XOM’s Vice President, Safety, Health and
Environment, stated 06.01.07: ‘We continue to look for opportunities where our expertise could help make a new energy technology viable on a large scale.’
To ensure any ‘new energy technology’ by ExxonMobil also helps move the U.S. toward energy independence in an environmentally sustainable way...
RESOLVED: shareholders request ExxonMobil’s Board of Directors to establish a Committee to study steps and report to shareholders, barring competitive information and disseminated at a reasonable expense, on how ExxonMobil can become
the industry leader within a reasonable period in developing and making available the technology needed (such as sequestration and engineered geothermal) to enable the U.S.A. to become energy independent in an environmentally sustainable way.”
The Board recommends you vote AGAINST this proposal for the following reasons:
ExxonMobil is an industry leader in technology. To identify and develop energy options and improve efficiency, ExxonMobil maintains industry-leading capabilities in research and development spanning many energy options. Our efforts include
proprietary research as well as support for and collaboration with leading academic and government laboratories.
As part of its base business strategy, ExxonMobil
actively pursues research and commercial activities that contribute to energy security throughout the world by broadening the portfolio of commercially viable energy resources and by extending the life of identified resources through improvements in
efficiency of energy supply and use. However, in opinion editorials and executive speeches, ExxonMobil strongly argues that the best way for the U.S., or any country, to successfully manage its energy needs is through interdependence, not energy
independence, because, as we have stated before, energy independence is not a realistic possibility.
Because these research and commercialization activities are part
of normal, ongoing business operations, the Board sees no need to publish a separate report aimed narrowly at the role of selected technologies in promoting energy independence for the U.S.
Current research activities include consideration of geothermal and other renewable energy sources, as well as efforts to use fossil fuels more efficiently and to reduce emissions,
for example, through carbon capture and storage.
Whether or not to commercialize such options is a business decision, based on ExxonMobil’s capabilities, market
analyses, and anticipated returns to shareholders. In the past year, ExxonMobil has announced the development of a new technology for on-board hydrogen reforming to power fuel cell vehicles and the deployment of new battery separator films for use
in lithium-ion batteries in hybrid and electric vehicles.
ITEM 19 – RENEWABLE ENERGY POLICY
This proposal was submitted by Mr. Stephen Viederman, 135 East 83rd Street, 15A, New
York, NY 10028, as lead proponent of a filing group.
“There is remarkable, near universal consensus among scientists regarding the need for aggressive action on
climate change, supported by an overwhelming non-partisan cross section of 84 percent of Americans (Opinion Research Corporation, 11/07), as well as a fast growing number of corporations in all sectors of the global economy.
We share the view of the World Energy Council and the International Energy Agency that carbon-based energy sources must be
significantly reduced, while undertaking a new focus on aggressively expanding renewable sources.
ExxonMobil Chair Rex Tillerson acknowledges ‘it is
increasingly clear that climate change poses risks to society and ecosystems that are serious enough to warrant action—by individuals, by businesses, and by governments.’
Energy efficiency and the advance of current proven emission-reducing technologies are necessary but not sufficient to significantly reduce climate impacts.
ExxonMobil ‘believes technology is an essential component of any long-term plan to address climate change risks,’ but has done little with regard to renewable technologies. This contrasts with the activities of
ExxonMobil’s competitors: BP, Royal Dutch Shell, and Chevron.
ExxonMobil’s 2007
Outlook for Energy: A View to 2030
projects renewables growing at 9
percent annually, oil and gas remaining indispensable to meet energy demand, and energy-related CO
2
emissions increasing to an annual level of 37 billion tons compared to 27
billion tons in 2005.
Mr. Tillerson recognizes ‘The energy challenges faced by the world are undeniable.’ ExxonMobil describes itself as ‘Taking
on the world’s toughest energy challenges.’ However, ExxonMobil’s failing to enunciate a renewables’ policy reflects the thinking of a traditional oil and gas company, not a farseeing energy company.
The urgency reflected in Mr. Tillerson’s statements is not reflected in ExxonMobil’s policies and actions regarding renewables.
The World Energy Council makes clear ‘it is a myth that the task of meeting the world’s energy needs while addressing climate change is simply too expensive and too
daunting.’
Breakthroughs in renewables will be made in the years ahead by companies in the forefront of renewables research and development. Responding to
increasing demand throughout the world—China has targeted 20% of its energy to come from renewables by 2020—will give corporate leaders a competitive advantage. While renewables now occupy a small market share, the availability of new and
better renewable technologies will not only fill the growing demand, but also create new demand.
ExxonMobil’s research and development capabilities are uniquely
positioned to meet the renewable energy challenge and bring it to scale creating competitive advantage for our company.
Significant research and development on
‘game-changing technologies for the long-term’ (Tillerson, 11/12/07) is needed now that will meet both energy demand, and social and environmental goals, criteria proposed by the World Energy Council.
As long-term investors looking to and beyond 2030, ExxonMobil’s
Energy Outlook’s
timeframe, we believe a farseeing renewable energy policy will create advantage
for our company.
We, therefore, ask your support for this resolution:
RESOLVED:
That ExxonMobil’s Board adopt a policy for renewable energy research, development and sourcing, reporting on its progress to investors in 2009.”
The
Board recommends you vote AGAINST this proposal for the following reasons:
The Corporation’s annual
Outlook for Energy – A View to 2030
highlights a substantial increase in energy demand in support of continued economic progress for the world’s growing population (available at
exxonmobil.com/energyoutlook
). To help meet this need, the Corporation is investing at record
levels in its traditional oil and gas development projects and is actively involved in research on alternative energy technologies. Therefore, the Board believes this proposal is unwarranted.
Experts agree that oil and gas, the Corporation’s primary business areas, will remain indispensable to meeting global energy demand for decades. In fact, consistent with the
Outlook for Energy
, the reference
case from the International Energy Agency (IEA) estimates that global oil and gas demand growth through 2030 will be close to 10 times the combined amount of growth in
biofuels, wind, solar, and geothermal. To meet oil and gas demand, the IEA projects the industry will need to invest, on average, approximately $380 billion a year through 2030. This signals a significant call on the scale and capabilities of the
Corporation and, with that, the opportunity to provide tremendous value.
At the same time, our active involvement in research on alternative energy technologies
enables the Corporation to readily assess new developments for possible commercialization, and investment as appropriate, to improve shareholder value. In addition to its own significant research, ExxonMobil is working with other institutions,
including Stanford University’s
Global Climate and Energy Project
, the U.S. Department of Energy, and the European Commission to support breakthrough research to help meet energy and environmental challenges.
Finally, the Corporation’s views on long-term future energy and environmental challenges – including potential development of game-changing technologies – are
already reported to the public through its annual
Outlook for Energy, Energy Trends
reports (2004 and 2006), and other communications including the annual
Corporate Citizenship Report
.
ADDITIONAL INFORMATION
Other Business
We
are not currently aware of any other business to be acted on at the meeting. Under the laws of New Jersey, where ExxonMobil is incorporated, no business other than procedural matters may be raised at the meeting unless proper notice has been
given to the shareholders. If other business is properly raised, your proxies have authority to vote as they think best, including to adjourn the meeting.
People
with Disabilities
We can provide reasonable assistance to help you participate in the meeting if you tell us about your disability and your plans to attend.
Please call or write the Secretary at least two weeks before the meeting at the telephone number, address, or fax number listed under “Contact Information” on page 3.
Outstanding Shares
On February 29, 2008, there were 5,331,546,810 shares of common stock outstanding. Each common share has one
vote.
How We Solicit Proxies
In addition to this mailing, ExxonMobil
officers and employees may solicit proxies personally, electronically, by telephone, or with additional mailings. ExxonMobil pays the costs of soliciting this proxy. We are paying D.F. King & Co. a fee of $30,000 plus expenses to help with
the solicitation. We also reimburse brokers and other nominees for their expenses in sending these materials to you and getting your voting instructions.
Shareholder Proposals for Next Year
Any shareholder proposal for the annual meeting in 2009 must be sent to the Secretary at the address or fax
number of ExxonMobil’s principal executive office listed under “Contact Information” on page 3. The deadline for receipt of a proposal to be considered for inclusion in the proxy statement is 5:00 p.m., Central Time, on
December 11, 2008. The deadline for notice of a proposal for which a shareholder will conduct his or her own solicitation is February 24, 2009. On request, the Secretary will provide instructions for submitting proposals.
Duplicate Annual Reports
Registered shareholders with multiple accounts may authorize
ExxonMobil to discontinue mailing extra annual reports by marking the “discontinue annual report mailing for this account” box on the proxy
card. If you vote via the Internet or by telephone, you will also have the opportunity to indicate that you wish to discontinue receiving extra annual reports. At
least one account must continue to receive an annual report. Eliminating these duplicate mailings will not affect receipt of future proxy statements and proxy cards.
Also, you may discontinue duplicate mailings by calling ExxonMobil Shareholder Services at the toll-free telephone number listed under “Contact Information” on page 4 at any time during the year. Beneficial holders can contact
their banks, brokers, or other holders of record to discontinue duplicate mailings.
Shareholders with the Same Address
If you share an address with one or more ExxonMobil shareholders, you may elect to “household” your proxy mailing. This means you will receive only one annual report and
proxy statement at that address unless one or more shareholders at that address specifically elect to receive separate mailings. Shareholders who participate in householding will continue to receive separate proxy cards. Also, householding will not
affect dividend check mailings. We will promptly send a separate annual report and proxy statement to a shareholder at a shared address on request. Shareholders with a shared address may also request us to send separate annual reports and proxy
statements in the future, or to send a single copy in the future if we are currently sending multiple copies to the same address.
Requests related to householding
should be made by calling ExxonMobil Shareholder Services at the telephone number listed under “Contact Information” on page 4. Beneficial shareholders can request information about householding from their banks, brokers, or other holders
of record.
Financial Statements
The year 2007 consolidated financial
statements and auditor’s report, management’s discussion and analysis of financial condition and results of operations, information concerning the quarterly financial data for the past two fiscal years, and other information, including
stock performance graphs, are provided in Appendix A.
SEC Form 10-K
Shareholders may obtain a copy of the Corporation’s
Annual Report on Form 10-K
to the Securities and Exchange Commission without charge by writing to the Secretary at the address listed under “Contact Information” on
page 3, or by visiting ExxonMobil’s Web site at
exxonmobil.com/financialpublications
.
Cumulative effect of accounting change, net of income tax
—
—
—
—
550
Net income
$
40,610
$
39,500
$
36,130
$
25,330
$
21,510
Net income per common share
Income from continuing operations
$
7.36
$
6.68
$
5.76
$
3.91
$
3.16
Net income per common share – assuming dilution
Income from continuing operations
$
7.28
$
6.62
$
5.71
$
3.89
$
3.15
Cumulative effect of accounting change, net of income tax
—
—
—
—
0.08
Net income
$
7.28
$
6.62
$
5.71
$
3.89
$
3.23
Cash dividends per common share
$
1.37
$
1.28
$
1.14
$
1.06
$
0.98
Net income to average shareholders’ equity (percent)
34.5
35.1
33.9
26.4
26.2
Working capital
$
27,651
$
26,960
$
27,035
$
17,396
$
7,574
Ratio of current assets to current liabilities
1.47
1.55
1.58
1.40
1.20
Additions to property, plant and equipment
$
15,387
$
15,462
$
13,839
$
11,986
$
12,859
Property, plant and equipment, less allowances
$
120,869
$
113,687
$
107,010
$
108,639
$
104,965
Total assets
$
242,082
$
219,015
$
208,335
$
195,256
$
174,278
Exploration expenses, including dry holes
$
1,469
$
1,181
$
964
$
1,098
$
1,010
Research and development costs
$
814
$
733
$
712
$
649
$
618
Long-term debt
$
7,183
$
6,645
$
6,220
$
5,013
$
4,756
Total debt
$
9,566
$
8,347
$
7,991
$
8,293
$
9,545
Fixed-charge coverage ratio (times)
49.9
46.3
50.2
36.1
30.8
Debt to capital (percent)
7.1
6.6
6.5
7.3
9.3
Net debt to capital (percent)
(3)
(24.0
)
(20.4
)
(22.0
)
(10.7
)
(1.2
)
Shareholders’ equity at year end
$
121,762
$
113,844
$
111,186
$
101,756
$
89,915
Shareholders’ equity per common share
$
22.62
$
19.87
$
18.13
$
15.90
$
13.69
Weighted average number of common shares outstanding (millions)
5,517
5,913
6,266
6,482
6,634
Number of regular employees at year end (thousands)
(4)
80.8
82.1
83.7
85.9
88.3
CORS employees not included above (thousands)
(5)
26.3
24.3
22.4
19.3
17.4
(1)
Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006, $30,742 million for 2005, $27,263 million for 2004 and $23,855
million for 2003.
(2)
Sales and other operating revenue includes $30,810 million for 2005, $25,289 million for 2004 and $20,936 million for 2003 for purchases/sales contracts with the same
counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies.
(3)
Debt net of cash, excluding restricted cash.
(4)
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.
(5)
CORS employees are employees of company-operated retail sites.
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 from sales of subsidiaries, investments
and property, plant and equipment 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 and financial 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 sales proceeds 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
2007
2006
2005
(millions of dollars)
Net cash provided by operating activities
$
52,002
$
49,286
$
48,138
Sales of subsidiaries, investments and property, plant and equipment
4,204
3,080
6,036
Cash flow from operations and asset sales
$
56,206
$
52,366
$
54,174
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 shareholders’ 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
2007
2006
2005
(millions of dollars)
Business uses: asset and liability perspective
Total assets
$
242,082
$
219,015
$
208,335
Less liabilities and minority share of assets and liabilities
Total current liabilities excluding notes and loans payable
(55,929
)
(47,115
)
(44,536
)
Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies
(50,543
)
(45,905
)
(41,095
)
Minority share of assets and liabilities
(5,332
)
(4,948
)
(4,863
)
Add ExxonMobil share of debt-financed equity company net assets
3,386
2,808
3,450
Total capital employed
$
133,664
$
123,855
$
121,291
Total corporate sources: debt and equity perspective
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 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
2007
2006
2005
(millions of dollars)
Net income
$
40,610
$
39,500
$
36,130
Financing costs (after tax)
Gross third-party debt
(339
)
(264
)
(261
)
ExxonMobil share of equity companies
(204
)
(156
)
(144
)
All other financing costs – net
268
499
(35
)
Total financing costs
(275
)
79
(440
)
Earnings excluding financing costs
$
40,885
$
39,421
$
36,570
Average capital employed
$
128,760
$
122,573
$
116,961
Return on average capital employed – corporate total
Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2)
Includes amounts for sales-based taxes.
(3)
Gross profit equals sales and other operating revenue less estimated costs associated with products sold.
The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal
market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.
There were 566,565 registered shareholders of ExxonMobil common stock at December 31, 2007. At January 31, 2008, the registered shareholders of ExxonMobil common stock numbered 561,103.
On January 30, 2008, the Corporation declared a $0.35 dividend per common share, payable March 10, 2008.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
Statements in this discussion regarding expectations, plans and future events or conditions are
forward-looking statements. Actual future results, including demand growth and energy source mix; capacity increases; production growth and mix; financing sources; the resolution of contingencies; the effect of changes in prices; interest rates and
other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and
petroleum and petrochemical products; and other factors discussed herein and in Item 1A of ExxonMobil’s 2007 Form 10-K.
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. Our consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the “triple-A”
status of its long-term debt securities for 89 years.
ExxonMobil, with its resource base, financial strength, disciplined investment
approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment
decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting
near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for
crude oil, natural gas and refined products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic
scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
By 2030, the world’s population is projected to grow to approximately 8 billion, more than 20 percent higher than today’s level. Coincident with this population
increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. This combination of population and economic growth is expected to lead to a primary energy demand increase of approximately 40 percent by 2030 versus
2005. The vast majority (~80 percent) of the increase is expected to occur in developing countries.
As demand rises, energy efficiency
will become increasingly important, with the rate of improvement projected to increase. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as
well as many other improvements that span the residential, commercial and industrial sectors. A wide variety of energy sources will be required to meet increasing global demand. Oil, gas and coal are expected to remain the predominant energy sources
with approximately 80 percent share of total energy. Oil and gas are projected to maintain close to a 60 percent share. These well-established fuel sources are the only ones with the versatility and scale to meet the majority of the world’s
growing energy needs over the outlook period. Nuclear power will likely be a growing option to meet electricity needs. Among renewable energy sources, wind, solar and biofuels are anticipated to grow rapidly at about 9 percent per year, reflecting
government subsidies and mandates. These energy sources are projected to reach approximately 2 percent of world energy by 2030, up from 0.5 percent currently.
Demand for liquid fuels is expected to grow at 1.3 percent per year from 2005 to 2030, primarily due to increasing transportation requirements, especially related to light- and heavy-duty vehicles. The global fleet of
light-duty vehicles will increase significantly, with related demand partly offset by improvements in fuel economy. Natural gas and coal are projected to grow at 1.7 and 0.9 percent per year, respectively, driven by rising needs for electric power
generation. The Corporation expects the liquefied natural gas (LNG) market to increase over 250 percent by 2030, with LNG imports helping to meet growing demand in Europe, North America and Asia. With equity positions in many of the largest remote
gas accumulations in the world, the Corporation is positioned to benefit from its technological advances in gas liquefaction, transportation and regasification that enable distant gas supplies to reach markets economically.
The Corporation anticipates that the world’s oil and gas resource base will grow not only from new discoveries, but also from increases to known
reserves. Technology will underpin these increases. The cost to develop these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be
about $380 billion per year, or about $9.5 trillion (measured in 2006 dollars) in total for 2006-2030.
Upstream
ExxonMobil continues to maintain a large portfolio of development and exploration opportunities, which enables the Corporation to be selective, optimizing total
profitability and mitigating overall political and technical risks. As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2012. Oil and natural gas
output from West Africa, the Caspian, the Middle East and Russia is expected to increase over the next five years based on current capital project execution plans. Currently, these growth areas account for 38 percent of the Corporation’s
production. By 2012, they are expected to generate about 50 percent of total volumes. The remainder of the Corporation’s production is expected to be sourced from established areas, including Europe, North America and Asia Pacific.
In addition to a changing geographic mix, there will also be a change in the type of opportunities from
which volumes are produced. Nonconventional production utilizing specialized technology such as arctic technology, deepwater drilling and production systems, heavy oil recovery processes and LNG is expected to grow from about 30 percent to over 40
percent of the Corporation’s output between now and 2012. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2008-2012. However, actual
volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors
described in Item 1A of ExxonMobil’s 2007 Form 10-K.
Downstream
ExxonMobil’s Downstream is a large, diversified business with marketing and refining complexes around the world. The Corporation has a strong presence in mature markets as well as in growing areas, such as the
Asia Pacific region. The objective of ExxonMobil’s Downstream strategies is to position the Corporation to be the industry leader under a variety of market conditions. These strategies include maintaining best-in-class operations in all aspects
of the business, maximizing value from leading-edge technology, capitalizing on integration with other ExxonMobil businesses, and providing quality, valued products and services to the Corporation’s customers.
The downstream industry environment remains very competitive. Refining margins have been relatively strong over the past few years. However,
inflation-adjusted refining margins over the prior 20 years have declined at a rate of about 1 percent per year. The intense competition in the retail fuels market has similarly driven down inflation-adjusted margins by about 3 percent per year.
Refining margins 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 IntercontinentalExchange). Prices for these commodities (crude and various
products) are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonal demand, weather and political
climate.
ExxonMobil has an ownership interest in 38 refineries, located in 21 countries, with distillation capacity of 6.3 million
barrels per day and lubricant basestock manufacturing capacity of about 140 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, serving a globally diverse customer base.
ExxonMobil’s Downstream capital expenditures are focused on selective and resilient investments. These investments capitalize on the
Corporation’s world-class scale and integration, industry-leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. For example, in
mid-2007, ExxonMobil along with our partners Saudi Aramco, Sinopec and the Fujian Province formed the only fully integrated refining, petrochemicals and fuels marketing venture with foreign participation in China. In addition, ExxonMobil
successfully started up several projects that produce lower-sulfur motor fuels, including gasoline projects in Japan and diesel projects in North America and Europe, with additional start-ups planned for 2008.
Chemical
The strength of the global economy supported continued
solid demand growth for petrochemicals in 2007. Strong economic and industrial production growth increased demand in Asia Pacific, particularly China. North American and European growth were moderate, similar to that of GDP. Overall the global
supply/demand balance remained tight, supporting continued strong margins despite higher feedstock costs.
ExxonMobil benefited from
continued operational excellence, as well as a portfolio of products that includes many of the largest-volume and highest-growth petrochemicals in the global economy. In addition to being a worldwide supplier of primary petrochemical products,
ExxonMobil Chemical also has a diverse portfolio of less-cyclical business lines. Chemical’s competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with
large refining complexes or Upstream gas processing, advantaged feedstock capabilities, leading proprietary technology and product application expertise.
REVIEW OF 2007 AND 2006 RESULTS
2007
2006
2005
(millions of dollars)
Net income (U.S. GAAP)
$
40,610
$
39,500
$
36,130
2007
Net
income in 2007 of $40,610 million was the highest ever for the Corporation, up $1,110 million from 2006. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.
Earnings in 2007 were also at record levels for each business segment.
2006
Net income in 2006 of $39,500 million was up $3,370 million from 2005. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Upstream
2007
2006
2005
(millions of dollars)
Upstream
United States
$
4,870
$
5,168
$
6,200
Non-U.S.
21,627
21,062
18,149
Total
$
26,497
$
26,230
$
24,349
2007
Upstream
earnings for 2007 totaled $26,497 million, an increase of $267 million from 2006. Higher liquids realizations were mostly offset by higher operating expenses and net unfavorable tax effects. Oil-equivalent production decreased 1 percent versus 2006,
including the Venezuela expropriation, divestments, OPEC quota effects and price and spend impacts on volumes. Excluding these impacts, total oil-equivalent production increased by 1 percent. Liquids production of 2,616 kbd (thousands of barrels per
day) decreased by 65 kbd from 2006. Production increases from new projects in West Africa and higher Russia volumes were offset by mature field decline and production sharing contract net interest reductions. Natural gas production of 9,384 mcfd
(millions of cubic feet per day) increased 50 mcfd from 2006. Higher volumes from projects in Qatar and the North Sea were mostly offset by mature field decline. Earnings from U.S. Upstream operations for 2007 were $4,870 million, a decrease of $298
million. Earnings outside the U.S. for 2007 were $21,627 million, an increase of $565 million.
2006
Upstream earnings for 2006 totaled $26,230 million, an increase of $1,881 million from 2005, including a $1,620 million gain related to the Dutch gas restructuring in
2005. Higher liquids and natural gas realizations were partly offset by higher operating expenses. Oil-equivalent production increased 4 percent versus 2005. Liquids production of 2,681 kbd increased by 158 kbd from 2005. Production increases from
new projects in West Africa and increased Abu Dhabi volumes were partly offset by mature field decline, entitlement effects and divestment impacts. Natural gas production of 9,334 mcfd increased 83 mcfd from 2005. Higher volumes from projects in
Qatar were partly offset by mature field decline. Earnings from U.S. Upstream operations for 2006 were $5,168 million, a decrease of $1,032 million. Earnings outside the U.S. for 2006 were $21,062 million, an increase of $2,913 million, including a
$1,620 million gain related to the Dutch gas restructuring in 2005.
Downstream
2007
2006
2005
(millions of dollars)
Downstream
United States
$
4,120
$
4,250
$
3,911
Non-U.S.
5,453
4,204
4,081
Total
$
9,573
$
8,454
$
7,992
2007
Downstream earnings totaled $9,573 million, an increase of $1,119 million from 2006. Improved worldwide refining operations and higher gains on asset sales, primarily outside the U.S., were partly offset by lower refining margins. Petroleum
product sales of 7,099 kbd decreased from 7,247 kbd in 2006, primarily due to divestment impacts. Refinery throughput was 5,571 kbd compared with 5,603 kbd in 2006, with the decrease again due to divestments. U.S. Downstream earnings of $4,120
million decreased by $130 million. Non-U.S. Downstream earnings of $5,453 million were $1,249 million higher than 2006.
2006
Downstream earnings totaled $8,454 million, an increase of $462 million from 2005, including a $310 million gain for the 2005 Sinopec share sale and a special charge of
$200 million related to the 2005 Allapattah lawsuit provision. Stronger worldwide refining and marketing margins were partly offset by lower refining throughput. Petroleum product sales of 7,247 kbd decreased from 7,519 kbd in 2005, primarily due to
lower refining throughput and divestment impacts. Refinery throughput was 5,603 kbd compared with 5,723 kbd in 2005. U.S. Downstream earnings of $4,250 million increased by $339 million, including a 2005 special charge related to the Allapattah
lawsuit provision. Non-U.S. Downstream earnings of $4,204 million were $123 million higher than 2005 earnings, which included a gain for the Sinopec share sale.
Chemical
2007
2006
2005
(millions of dollars)
Chemical
United States
$
1,181
$
1,360
$
1,186
Non-U.S.
3,382
3,022
2,757
Total
$
4,563
$
4,382
$
3,943
2007
Chemical
earnings totaled $4,563 million, an increase of $181 million from 2006. Increased 2007 earnings were driven by higher sales volumes and favorable foreign exchange effects partly offset by lower margins. Prime product sales were 27,480 kt (thousands
of metric tons), an increase of 130 kt. Prime product sales are total chemical product sales, including ExxonMobil’s share of equity-company volumes and finished-product transfers to the Downstream business. Carbon black oil and sulfur volumes
are excluded. U.S. Chemical earnings of $1,181 million decreased by $179 million. Non-U.S. Chemical earnings of $3,382 million were $360 million higher than 2006.
Chemical
earnings totaled $4,382 million, an increase of $439 million from 2005, including a $390 million gain from the favorable resolution of joint venture litigation in 2005 and a $150 million gain for the 2005 Sinopec share sale. Increased 2006 earnings
were driven by higher margins and increased sales volumes. Prime product sales were 27,350 kt, an increase of 573 kt. U.S. Chemical earnings of $1,360 million increased by $174 million. Non-U.S. Chemical earnings of $3,022 million were $265 million
higher than 2005 earnings, which included gains from the favorable resolution of joint venture litigation and the Sinopec share sale.
Corporate and
Financing
2007
2006
2005
(millions of dollars)
Corporate and financing
$
(23
)
$
434
$
(154
)
2007
Corporate and financing expenses were $23 million in 2007, compared to an earnings contribution of $434 million in 2006, which included a $410 million gain from tax benefits related to historical investments in non-U.S. assets.
2006
The corporate and financing segment contributed $434 million
to earnings in 2006, up $588 million from 2005, primarily due to a $410 million gain from tax benefits related to historical investments in non-U.S. assets and higher interest income.
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
2007
2006
(millions of dollars)
Net cash provided by/(used in)
Operating activities
$
52,002
$
49,286
Investing activities
(9,728
)
(14,230
)
Financing activities
(38,345
)
(36,210
)
Effect of exchange rate changes
1,808
727
Increase/(decrease) in cash and cash equivalents
$
5,737
$
(427
)
(Dec. 31)
Cash and cash equivalents
$
33,981
$
28,244
Cash and cash equivalents – restricted
—
4,604
Total cash and cash equivalents
$
33,981
$
32,848
Cash and cash equivalents were $34.0 billion at the end of 2007, $5.7 billion higher than the prior year,
reflecting a $4.6 billion increase due to the release of the restriction on the restricted cash and cash equivalents and $1.8 billion of positive foreign exchange effects from the weakening of the U.S. dollar in 2007. There were no restricted cash
and cash equivalents at the end of 2007 (see note 3 and note 15).
Cash and cash equivalents were $28.2 billion at the end of 2006, comparable to the prior
year, as a net reduction from operating, investing and financing activities was partly offset by $0.7 billion of positive foreign exchange effects from the weakening of the U.S. dollar in 2006. Including restricted cash and cash equivalents of $4.6
billion (see note 3 and note 15), total cash and cash equivalents were $32.8 billion at the end of 2006. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of
Cash Flows.
Although the Corporation issues long-term debt from time to time and has access to short-term
liquidity, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully controlled, both to optimize returns
on cash balances, and to ensure that it is secure and readily available to meet the Corporation’s cash requirements.
To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to
existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all
the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at approximately 6 percent per year, consistent with recent historical performance. 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, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can
vary with price and contractual terms.
The Corporation has long been successful at offsetting the effects
of natural field decline through disciplined investments and anticipates similar results in the future. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including
project start-up timing, operational outages, reservoir performance, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices.
The Corporation’s financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make
large, long-term capital expenditures. Capital and exploration expenditures in 2007 were $20.9 billion, reflecting the Corporation’s continued active investment program. The Corporation expects spending in the range from $25 billion to $30
billion for the next several years. Actual spending could vary depending on the progress of individual projects. 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. The purchase and sale of oil and gas properties have not had a significant
impact on the amount or timing of cash flows from operating activities.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cash Flow from operating activities
2007
Cash provided by operating activities totaled $52.0 billion in 2007, a $2.7 billion increase from 2006. The major source of funds was net income of $40.6 billion,
adjusted for the noncash provision of $12.3 billion for depreciation and depletion, both of which increased.
2006
Cash provided by operating activities totaled $49.3 billion in 2006, a $1.1 billion increase from 2005. The major source of funds was net income of $39.5 billion,
adjusted for the noncash provision of $11.4 billion for depreciation and depletion, both of which increased. The net timing effects of receipts of notes and accounts receivable, payments of accounts and other payables and contributions to pension
funds in 2006 provided a partial offset.
Cash Flow from Investing Activities
2007
Cash used in investing activities netted to $9.7 billion in 2007, $4.5 billion lower than in 2006. Spending for
property, plant and equipment of $15.4 billion in 2007 was comparable to the prior year. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $4.2 billion in 2007 increased $1.1 billion, reflecting a higher level
of asset sales in the Downstream business. Additions from the release of the restriction on the restricted cash and cash equivalents were $4.6 billion. Net investments and advances and net additions to marketable securities were $1.3 billion higher
in 2007.
2006
Cash used in investing activities
totaled $14.2 billion in 2006, $4.0 billion higher than 2005. Spending for property, plant and equipment increased $1.6 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $3.1 billion in 2006 decreased
$3.0 billion, reflecting a lower level of asset sales and the absence of almost $1.4 billion from the sale of the Corporation’s interest in Sinopec in 2005.
Cash Flow from Financing Activities
2007
Cash used in financing activities was $38.3 billion, an increase of $2.1 billion from 2006, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.37 per share from $1.28 per share
and totaled $7.6 billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $1.2 billion to $9.6 billion at year-end 2007.
Shareholders’ equity increased $7.9 billion in 2007, to $121.8 billion, reflecting $40.6 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of dividends and $28.0 billion of
purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, increased $4.2 billion, representing the foreign exchange translation effects of stronger foreign currencies at the end
of 2007 on ExxonMobil’s operations outside the United States.
During 2007, Exxon Mobil Corporation purchased 386 million shares
of its common stock for the treasury at a gross cost of $31.8 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were
reduced by 6.1 percent from 5,729 million at the end of 2006 to 5,382 million at the end of 2007. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any
time without prior notice.
2006
Cash used in
financing activities was $36.2 billion, an increase of $9.3 billion from 2005, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.28 per share from $1.14 per share and totaled $7.6
billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $0.3 billion to $8.3 billion at year-end 2006.
Shareholders’ equity increased $2.7 billion in 2006, to $113.8 billion, reflecting $39.5 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of
dividends and $25.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, increased $2.8 billion, representing the foreign exchange translation effects of stronger
foreign currencies at the end of 2006 on ExxonMobil’s operations outside the United States. Recognition of the “Postretirement benefits reserves adjustment” under Financial Accounting Standard No. 158 (see note 16) reduced
shareholders’ equity by $6.5 billion.
During 2006, Exxon Mobil Corporation purchased 451 million
shares of its common stock for the treasury at a gross cost of $29.6 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were
reduced by 6.6 percent from 6,133 million at the end of 2005 to 5,729 million at the end of 2006. Purchases were made in both the open market and through negotiated transactions.
Set
forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2007. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial
Statements.
Payments Due by Period
Commitments
Note
Reference
Number
2008
2009-
2012
2013
and
Beyond
Total
(millions of dollars)
Long-term debt (1)
13
$
—
$
2,910
$
4,273
$
7,183
– Due in one year (2)
318
—
—
318
Asset retirement obligations (3)
8
307
1,182
3,652
5,141
Pension and other postretirement obligations (4)
16
1,392
3,654
7,851
12,897
Operating leases (5)
10
1,994
5,358
2,564
9,916
Unconditional purchase obligations (6)
15
490
1,497
778
2,765
Take-or-pay obligations (7)
956
2,851
2,369
6,176
Firm capital commitments (8)
7,290
6,332
1,512
15,134
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 net unrecognized tax benefits totaling $4.5 billion as of December 31, 2007, 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 18, Income, Sales-Based and Other Taxes.
Notes:
(1)
Includes capitalized lease obligations of $409 million.
(2)
The amount due in one year is included in notes and loans payable of $2,383 million (note 5).
(3)
The discounted present value of upstream asset retirement obligations, primarily 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 2008 and estimated benefit payments for unfunded plans in all years.
(5)
Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties.
(6)
Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable and that third parties have used to secure financing for the facilities that will
provide the contracted goods or services. The undiscounted obligations of $2,765 million mainly pertain to pipeline throughput agreements and include $1,847 million of obligations to equity companies. The present value of the total commitments,
which excludes imputed interest of $562 million, was $2,203 million.
(7)
Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $6,176 million mainly pertain to
manufacturing supply, pipeline and terminaling agreements and include $1,526 million of obligations to equity companies. The present value of the total commitments, which excludes imputed interest of $1,308 million, totaled $4,868 million.
(8)
Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $15.1 billion. These commitments were primarily associated with Upstream projects
outside the U.S., of which $5.5 billion was associated with West African projects. The Corporation expects to fund the majority of these projects through internal cash flow.
Guarantees
The Corporation and certain of its consolidated
subsidiaries were contingently liable at December 31, 2007, for $5,148 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of
$4,591 million, representing ExxonMobil’s share of obligations of certain equity companies. The below-mentioned 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.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financial Strength
On December 31, 2007, unused credit lines for
short-term financing totaled approximately $5.7 billion (note 5).
The table below shows the Corporation’s fixed-charge coverage and
consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness. Throughout this period, the Corporation’s long-term debt securities maintained the top credit rating from both Standard & Poor’s
(AAA) and Moody’s (Aaa), a rating it has sustained for 89 years.
2007
2006
2005
Fixed-charge coverage ratio (times)
49.9
46.3
50.2
Debt to capital (percent)
7.1
6.6
6.5
Net debt to capital (percent)
(24.0)
(20.4)
(22.0)
Credit rating
AAA/Aaa
AAA/Aaa
AAA/Aaa
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.
The Corporation
makes limited use of derivative instruments, which are discussed in note 12.
Litigation and Other Contingencies
Litigation
As discussed in note 15, a number of lawsuits, including
class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims have been resolved and
paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. The first judgment from the United States District Court for the District of Alaska in the amount of $5 billion was vacated by the United States Court
of Appeals for the Ninth Circuit as being excessive under the Constitution. The second judgment in the amount of $4 billion was vacated by the Ninth Circuit panel without argument and sent back for the District Court to reconsider in light of the
recent U.S. Supreme Court decision in
Campbell v. State Farm
. The most recent District Court judgment for punitive damages was for $4.5 billion plus interest and was entered in January 2004. The Corporation posted a $5.4 billion letter of
credit. ExxonMobil and the plaintiffs appealed this decision to the Ninth Circuit, which ruled on December 22, 2006, that the award be reduced to $2.5 billion. On January 12, 2007, ExxonMobil petitioned the Ninth Circuit Court of Appeals
for a rehearing en banc of its appeal. On May 23, 2007, with two dissenting opinions, the Ninth Circuit determined not to re-hear ExxonMobil’s appeal before the full court. ExxonMobil filed a petition for writ of certiorari to the U.S.
Supreme Court on August 20, 2007. On October 29, 2007, the U.S. Supreme Court granted ExxonMobil’s petition for a writ of certiorari. Oral argument was held on February 27, 2008. While it is reasonably possible that a liability
for punitive damages may have been incurred from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.
In December 2000, a jury in the 15th Judicial Circuit Court of Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over
royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of
Exxon Corporation v. State of Alabama, et al.
The verdict was upheld by the trial court in May 2001. In December 2002, the
Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and in November 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in
compensatory damages and $11.8 billion in punitive damages. In March 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil appealed the decision to the Alabama Supreme Court. On November 1, 2007, the
Alabama Supreme Court reversed the trial court’s fraud judgment and instructed the district court to enter judgment for ExxonMobil on the fraud claim, eliminating the punitive damage award. The Court also ruled in ExxonMobil’s favor on
some of the disputed lease issues, reducing the compensatory award to $52 million plus interest. Following the Alabama Supreme Court’s decision, an appeal bond was canceled and the collateral was subsequently released.
In 2001, a Louisiana state court jury awarded compensatory damages of $56 million and punitive damages of $1 billion to a
landowner for damage caused by a third party that leased the property from the landowner. The third party provided pipe cleaning and storage services for the Corporation and other entities. The Louisiana Fourth Circuit Court of Appeals reduced the
punitive damage award to $112 million in 2005. The Corporation appealed this decision to the Louisiana Supreme Court which, in March 2006, refused to hear the appeal. ExxonMobil has fully accrued and paid the compensatory and punitive damage awards.
The Corporation appealed the punitive damage award to the U.S. Supreme Court, which on February 26, 2007, vacated the judgment and remanded the case to the Louisiana Fourth Circuit Court of Appeals for reconsideration in light of the recent
U.S. Supreme Court decision in
Williams v. Phillip Morris USA
. On August 8, 2007, the Fourth Circuit issued its decision on remand and declined to reduce the punitive damage award. On November 16, 2007, the Louisiana Supreme Court
denied ExxonMobil’s writ for review of the Fourth Circuit’s decision. ExxonMobil has appealed to the U.S. Supreme Court.
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 materially adverse effect upon the Corporation’s operations or financial condition. 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.
Other Contingencies
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 PdVSA, and on June 27, 2007, the
government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
To date, discussions with Venezuelan
authorities have not resulted in an agreement on the amount of compensation to be paid to ExxonMobil. On September 6, 2007, ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes.
ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. At this time, the net
impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial
condition. At the time the assets were expropriated, ExxonMobil’s remaining net book investment in Cerro Negro producing assets was about $750 million.
CAPITAL AND EXPLORATION EXPENDITURES
2007
2006
U.S.
Non-U.S.
U.S.
Non-U.S.
(millions of dollars)
Upstream
(1)
$
2,212
$
13,512
$
2,486
$
13,745
Downstream
1,128
2,175
824
1,905
Chemical
360
1,422
280
476
Other
44
—
130
9
Total
$
3,744
$
17,109
$
3,720
$
16,135
(1)
Exploration expenses included.
Capital and exploration
expenditures in 2007 were $20.9 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could
vary depending on the progress of individual projects.
Upstream spending of $15.7 billion in 2007 was down 3 percent from 2006, mainly due
to timing of project implementation and related expenditures. During the past three years, Upstream capital and exploration expenditures averaged $15.5 billion. The majority of these expenditures are on development projects, which typically take two
to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total
proved reserves, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital and exploration expenditures are not tracked by the undeveloped and developed proved reserve categories. Capital investments in the
Downstream totaled $3.3 billion in 2007, an increase of $0.6 billion from 2006, as a result of new investment in China and higher environmental expenditures. Chemical 2007 capital expenditures of $1.8 billion were up $1.0 billion from 2006 due to
increased investment in Singapore and China to meet Asia Pacific demand growth.
TAXES
2007
2006
2005
(millions of dollars)
Income taxes
$
29,864
$
27,902
$
23,302
Sales-based taxes
31,728
30,381
30,742
All other taxes and duties
44,091
42,393
44,571
Total
$
105,683
$
100,676
$
98,615
Effective income tax rate
44
%
43
%
41
%
2007
Income,
sales-based and all other taxes totaled $105.7 billion in 2007, an increase of $5.0 billion or 5 percent from 2006. Income tax expense, both current and deferred, was $29.9 billion, $2.0 billion higher than 2006, reflecting higher pre-tax income in
2007. The effective tax rate was 44 percent in 2007, compared to 43 percent in 2006. Sales-based and all other taxes and duties of $75.8 billion in 2007 increased $3.0 billion from 2006, reflecting higher prices.
2006
Income, sales-based and all other taxes and duties totaled
$100.7 billion in 2006, an increase of $2.1 billion or 2 percent from 2005. Income tax expense, both current and deferred, was $27.9 billion, $4.6 billion higher than 2005, reflecting higher pre-tax income in 2006. The effective tax rate was 43
percent in 2006, compared to 41 percent in 2005. During both periods, the Corporation continued to benefit from the favorable resolution of tax-related issues. Sales-based and all other taxes and duties of $72.8 billion in 2006 decreased $2.5
billion from 2005, reflecting the tax impact of net reporting of purchases and sales of inventory with the same counterparty, only partly offset by the effects of higher prices.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ENVIRONMENTAL MATTERS
Environmental Expenditures
2007
2006
(millions of dollars)
Capital expenditures
$
1,525
$
1,081
Other expenditures
2,272
2,127
Total
$
3,797
$
3,208
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 reduce nitrogen oxide and sulfur oxide emissions and expenditures for asset
retirement obligations. ExxonMobil’s 2007 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $3.8 billion. The total cost for such
activities is expected to remain in this range in 2008 and 2009 (with capital expenditures approximately 45 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 2007 for environmental liabilities were $432 million ($350 million
in 2006) and the balance sheet reflects accumulated liabilities of $916 million as of December 31, 2007, and $864 million as of December 31, 2006.
Asset Retirement Obligations
The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when
they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($113 million for 2007). Over time, the liabilities are accreted for the increase in their present
value, with this effect included in expenses ($322 million in 2007). Consolidated company expenditures for asset retirement obligations in 2007 were $352 million and the ending balance of the obligations recorded on the balance sheet at
December 31, 2007, totaled $5,141 million.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations
(1)
2007
2006
2005
Crude oil and NGL ($/barrel)
$
66.02
$
58.34
$
48.23
Natural gas ($/kcf)
5.29
6.08
5.96
(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, based on the 2007 worldwide
production levels, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $400 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the
worldwide average gas realization would have approximately a $200 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 a broad indicator 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.
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, including the AAA and Aaa ratings of its long-term debt securities by Standard & Poor’s and Moody’s, 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 40 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the
Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to
medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its assets over a broad
range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities
are tested against a variety of market conditions, including low-price scenarios. As a result, investments that would succeed only in highly favorable price environments are screened out of the investment plan.
The Corporation has had an active asset management program in which underperforming assets are either improved to acceptable levels or considered for
divestment. The asset management program involves a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic and financial objectives. The result has been the creation of an efficient capital base
and has meant that the Corporation has seldom been required to write down the carrying value of assets, even during periods of low commodity prices.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream,
Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the
impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the
authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Note 12 summarizes the
fair value of derivatives outstanding at year end and the gains or losses that have been recognized in net income.
The Corporation is
exposed to changes in interest rates, primarily as a result of its short-term debt and long-term debt carrying 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’s cash balances exceeded total debt at year-end 2007 and 2006.
The
Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s
geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts, commodity forwards, swaps and futures contracts to mitigate the impact of changes in
currency values and commodity prices. Exposures related to the Corporation’s limited use of the above contracts are not material.
Inflation and
Other Uncertainties
The general rate of inflation in most major countries of operation has been relatively low in recent years and the associated
impact on costs has generally been countered by cost reductions from efficiency and productivity improvements. Increased global demand for certain services and materials has resulted in higher operating and capital costs in recent years. The
Corporation continues to mitigate these effects through its economies of scale in global procurement and its efficient project management practices.
RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS
Fair Value Measurements
In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157 (FAS 157), “Fair Value Measurements.” FAS 157 defines fair
value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements.
FAS 157 must be adopted by the Corporation no later than January 1, 2008, for all financial assets and liabilities that are measured at fair value
and nonfinancial assets and liabilities that are remeasured at fair value at least annually. FAS 157 must be adopted no later than January 1, 2009, for nonfinancial assets and liabilities that are not remeasured at fair value at least annually.
The Corporation does not expect the adoption of FAS 157 to have a material impact on the Corporation’s financial statements.
Noncontrolling
Interests in Consolidated Financial Statements
In December 2007, the FASB issued Statement No. 160 (FAS 160), “Noncontrolling Interests in
Consolidated Financial Statements – an Amendment of ARB No. 51.” FAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as non-controlling interests and classified as a component of equity.
FAS 160 must be adopted by the Corporation no later than January 1, 2009. FAS 160 requires retrospective adoption of the presentation
and disclosure requirements for existing minority interests. All other requirements of FAS 160 will be applied prospectively. The Corporation does not expect the adoption FAS 160 to have a material impact on the Corporation’s financial
statements.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING POLICIES
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 following summary provides further information about the critical accounting
policies and the judgments that are made by the Corporation in the application of those policies.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas
properties such as whether development should proceed or enhanced recovery methods should be undertaken. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment.
Oil and gas reserves include both proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less than reasonable certainty of recoverability and
include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
The estimation of proved
reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure
declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering
professionals (assisted by a central reserves group with 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 reserves estimation process include:
•
rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines) and
•
a requirement that management make significant funding commitments toward the development of the reserves prior to reporting as proved.
Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered
can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves has remained relatively
stable over the past five years at over 60 percent of total proved reserves (including both consolidated and equity company reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, these
undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development
projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.
The year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities
are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time
measure to calculate reserves and to enhance comparability between companies.
Regulations preclude the
Corporation from showing in this document the reserves that are calculated in a manner that is consistent with the basis that the Corporation uses to make its investment decisions. The use of year-end prices for reserves estimation introduces
short-term price volatility into the process, since annual adjustments are required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where
production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of
consequence in how the business is actually managed.
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 year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production
equipment/facility capacity.
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 with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry
holes are capitalized and amortized on the unit-of-production method. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the
Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The
full cost method would tend to delay the expense recognition of unsuccessful projects.
Impact of Oil and Gas Reserves on Depreciation.
The calculation of unit-of-production depreciation is a critical
accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating
methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions
the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.
Impact of Oil and Gas Reserves and Prices on Testing for Impairment.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment
whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts.
In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were
less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
The Corporation
performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying
amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a
significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current operating losses.
In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for
crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry
production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global
economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the
Corporation’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment
decisions. Volumes are based on individual field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the use of derivative instruments.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated
financial statements. The standardized measure of discounted future cash flows is based on the year-end price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69), “Disclosure about
Oil and Gas Producing Activities.” Future prices used for any impairment tests will vary from the one used in the FAS 69 disclosure and could be lower or higher for any given year.
Suspended Exploratory Well Costs
The Corporation carries as an asset exploratory well costs 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. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support
continued capitalization of suspended wells as of year-end 2007 are disclosed in note 9 to the financial statements.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Consolidations
The Consolidated Financial Statements include the
accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the
underlying net assets of other significant affiliates that it does not control, but 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.” The accounting for these non-consolidated companies is referred to as the equity method of accounting.
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.
Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 6.
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 percentage 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 percentage share of all assets and liabilities in these partially owned companies rather than only its percentage in the net equity. This method of
accounting for investments in partially owned companies is not permitted by 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 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 approximately 100 defined benefit (pension) plans in
about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Pension and Other Postretirement Benefits (note 16) provides details on pension
obligations, fund assets and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by
their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension
cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are
paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including many in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements.
These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining
liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the
financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires
explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside
actuaries and senior management. These assumptions are adjusted only as appropriate to reflect changes in market rates and outlook. For example, the long-term expected earnings rate on U.S. pension plan assets in 2007 was 9.0 percent. This compares
to an actual rate of return over the past decade of 10 percent. 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 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 $140 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 15.
GAAP requires that liabilities for
contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that 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.
Significant 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 materially 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.
GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its
income tax returns. The benefit of an uncertain tax position can only be 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 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 18.
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. Downstream and Chemical operations use the local currency, except in countries with a history of high inflation
(primarily in Latin America) and Singapore, which uses the U.S. dollar because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas
production is predominantly sold in the export market in U.S. dollars. Operations using the U.S. dollar as their functional currency include Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea, Russia and the Middle East.
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
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 the
Internal Control – Integrated Framework
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, 2007.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2007, as stated in their report included in
the Financial Section of this report.
Rex W. Tillerson
Donald D. Humphreys
Patrick T. Mulva
Chief Executive Officer
Sr. Vice President and Treasurer
(Principal Financial
Officer)
Vice President and Controller
(Principal Accounting
Officer)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Exxon Mobil Corporation:
In our opinion, the consolidated financial statements listed under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at
December 31, 2007, and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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, 2007, based on criteria established in
Internal Control – Integrated
Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and
on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our
audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits
provide a reasonable basis for our opinions.
As discussed in Note 2 to the consolidated financial statements, the Corporation changed its method of accounting for
uncertainty in income taxes in 2007.
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.
Income applicable to minority and preferred interests
1,005
1,051
799
Total costs and other deductions
$
334,078
$
310,233
$
311,248
Income before income taxes
$
70,474
$
67,402
$
59,432
Income taxes
18
29,864
27,902
23,302
Net income
$
40,610
$
39,500
$
36,130
Net income per common share (dollars)
11
$
7.36
$
6.68
$
5.76
Net income per common share – assuming dilution (dollars)
11
$
7.28
$
6.62
$
5.71
(1)
Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005.
(2)
Sales and other operating revenue includes $30,810 million for 2005 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and
product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies.
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
The accompanying consolidated financial statements and the supporting and
supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business is
energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide
manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream).
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 2007 presentation basis.
1.
Summary of Accounting Policies
Principles of Consolidation.
The Consolidated Financial Statements include the accounts
of those subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include
the Corporation’s share of the undivided interest in certain upstream assets and liabilities.
Amounts representing the
Corporation’s percentage interest in the underlying net assets of other subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held 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.” The Corporation’s share of the cumulative foreign
exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Shareholders’ Equity. 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, a negative earnings and cash flow
outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount
is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Revenue Recognition.
The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under
long-term agreements, with periodic price adjustments. In all cases, 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.
Effective January 1, 2006, the Corporation adopted the Emerging Issues Task Force (EITF) consensus on Issue No. 04-13, “Accounting for
Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges
measured at the book value of the item sold. In prior periods, the Corporation recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases contemporaneously negotiated with the same counterparty as revenues and
purchases. As a result of the EITF consensus, the Corporation’s accounts “Sales and other operating revenue,” “Crude oil and product purchases” and “Other taxes and duties” on the Consolidated Statement of Income
were reduced prospectively from 2006 by associated amounts with no impact on net income. All operating segments were affected by this change, with the largest impact in the Downstream.
Sales-Based Taxes.
The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross
reporting basis is footnoted on the Consolidated Statement of Income.
Derivative Instruments.
The Corporation makes limited use of derivative
instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset
exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and transactions.
The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are
offset in income by the gains and losses arising from changes in the fair value of the underlying hedged items.
Inventories.
Crude oil, products and merchandise inventories are carried at the lower of current market value or
cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and
location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment.
Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under
either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major
renewals and improvements are capitalized and the assets replaced are retired.
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.
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 with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.
The Corporation carries as an asset exploratory well costs 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.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas
reserves. 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. The cost of properties that are not individually significant are aggregated by groups and amortized over the average holding period of the properties of the groups. The valuation allowances are reviewed at least
annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred.
Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties in the Upstream segment.
Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods. Additional oil and gas to be obtained through
the application of improved recovery techniques is included when, or to the extent that, the requisite commercial-scale facilities have been installed and the required wells have been drilled.
Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales
transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves
lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs
are those incurred to operate and maintain the Corporation’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor
costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the
production activity.
Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery
of costs applicable to any interest retained or where there is no 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.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups
of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to
judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual
volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation
purposes. Cash flow estimates for impairment testing exclude derivative instruments.
Impairment analyses
are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair
value.
Asset Retirement Obligations and Environmental Liabilities.
The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as
liabilities on a discounted basis. 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, West Africa, Russia and the Middle East, 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.
Share-Based Payments.
The Corporation awards share-based compensation to employees in the form of restricted stock and restricted stock units.
Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See note 14, Incentive Program, for further details.
2.
Accounting Change for Uncertainty in Income Taxes
Effective January 1, 2007, the Corporation adopted the Financial
Accounting Standards Board’s (FASB) Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes.” FIN 48 is an interpretation of FASB Statement 109, “Accounting for Income Taxes,” and prescribes a
comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. Upon the adoption of FIN 48, the Corporation
recognized a transition gain of $267 million in shareholders’ equity. The gain reflected the recognition of several refund claims, partly offset by increased liability reserves. FIN 48 also resulted in a reclassification of amounts previously
reported net on the balance sheet. The balance sheet reclassifications resulted in a $2.4 billion increase to investments, advances and long-term receivables, a $1.0 billion decrease to current liabilities, primarily income taxes payable, and a $3.1
billion increase to other long-term obligations. See note 18, Income, Sales-Based and Other Taxes, for additional disclosures.
3.
Miscellaneous Financial Information
Research and development costs totaled $814 million in 2007, $733 million in 2006 and
$712 million in 2005.
Net income included aggregate foreign exchange transaction gains of $229 million and $278 million in 2007 and 2006,
respectively, and losses of $138 million in 2005.
In 2007, 2006 and 2005, net income included gains of $327 million, $401 million and $215
million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $25.4 billion and $15.9 billion at
December 31, 2007, and 2006, respectively.
Crude oil, products and merchandise as of year-end 2007 and 2006 consist of the following:
2007
2006
(billions of dollars)
Petroleum products
$
3.8
$
3.8
Crude oil
2.6
2.8
Chemical products
2.1
2.1
Gas/other
0.4
0.3
Total
$
8.9
$
9.0
The restriction on approximately $4.6 billion of cash and cash equivalents was released in 2007
following an Alabama Supreme Court judgment in ExxonMobil’s favor (see note 15).
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.
The
“Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes the before-tax gain from the Corporation’s sale of its investment in Sinopec in 2005. Other gains are
primarily from the sale of Downstream assets and investments in 2007 and from the sale of Upstream producing properties in 2006 and 2005. These gains are reported in “Other income” on the Consolidated Statement of Income.
2007
2006
2005
(millions of dollars)
Cash payments for interest
$
555
$
1,382
$
473
Cash payments for income taxes
$
26,342
$
26,165
$
22,535
5.
Additional Working Capital Information
Dec. 31
2007
Dec. 31
2006
(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $258 million and $306 million
$
30,775
$
25,076
Other, less reserves of $36 million and $64 million
5,675
3,866
Total
$
36,450
$
28,942
Notes and loans payable
Bank loans
$
1,238
$
753
Commercial paper
205
274
Long-term debt due within one year
318
459
Other
622
216
Total
$
2,383
$
1,702
Accounts payable and accrued liabilities
Trade payables
$
29,239
$
25,084
Payables to equity companies
3,556
2,597
Accrued taxes other than income taxes
6,485
6,052
Other
5,995
5,349
Total
$
45,275
$
39,082
On December 31, 2007, unused credit lines for short-term financing totaled approximately $5.7 billion. Of
this total, $3.6 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2007, and 2006, was 5.5 percent.
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 crude production, natural gas
marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several
power generation, refining, petrochemical/lubes manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total
equity company revenues from sales to ExxonMobil consolidated companies was 23 percent, 24 percent and 22 percent in the years 2007, 2006 and 2005, respectively.
2007
2006
2005
Equity Company Financial Summary
Total
ExxonMobil
Share
Total
ExxonMobil
Share
Total
ExxonMobil
Share
(millions of dollars)
Total revenues
$
109,149
$
37,724
$
98,542
$
33,505
$
88,003
$
31,395
Income before income taxes
$
30,505
$
11,448
$
24,094
$
8,905
$
24,070
$
9,809
Income taxes
7,557
2,547
5,582
1,920
5,574
2,226
Net income
$
22,948
$
8,901
$
18,512
$
6,985
$
18,496
$
7,583
Current assets
$
29,268
$
10,228
$
24,684
$
8,484
$
24,931
$
8,645
Property, plant and equipment, less accumulated depreciation
70,591
22,638
59,691
19,602
50,622
17,149
Other long-term assets
6,667
3,092
7,209
4,206
6,900
3,919
Total assets
$
106,526
$
35,958
$
91,584
$
32,292
$
82,453
$
29,713
Short-term debt
$
3,127
$
1,117
$
2,669
$
888
$
3,412
$
1,179
Other current liabilities
20,861
7,124
16,543
5,852
15,330
5,414
Long-term debt
19,821
2,269
16,442
1,920
13,419
2,271
Other long-term liabilities
8,142
3,395
7,946
3,250
7,477
3,153
Advances from shareholders
18,422
8,353
15,791
6,803
14,390
5,580
Net assets
$
36,153
$
13,700
$
32,193
$
13,579
$
28,425
$
12,116
A list of significant equity companies as of December 31, 2007, together with the Corporation’s
percentage ownership interest, is detailed below:
Percentage
Ownership
Interest
Upstream
Aera Energy LLC
48
BEB Erdgas und Erdoel GmbH
50
Cameroon Oil Transportation Company S.A.
41
Castle Peak Power Company Limited
60
Nederlandse Aardolie Maatschappij B.V.
50
Qatar Liquefied Gas Company Limited
10
Qatar Liquefied Gas Company Limited II
24
Ras Laffan Liquefied Natural Gas Company Limited
25
Ras Laffan Liquefied Natural Gas Company Limited II
7.
Investments, Advances and Long-Term Receivables
Dec. 31
2007
Dec. 31
2006
(millions of dollars)
Companies carried at equity in underlying assets
Investments
$
13,700
$
13,579
Advances
8,353
6,803
$
22,053
$
20,382
Companies carried at cost or less and stock investments carried at fair value
1,647
1,678
$
23,700
$
22,060
Long-term receivables and miscellaneous investments at cost or less
4,494
1,177
Total
$
28,194
$
23,237
8.
Property, Plant and Equipment and Asset Retirement Obligations
Dec. 31, 2007
Dec. 31, 2006
Property, Plant and Equipment
Cost
Net
Cost
Net
(millions of dollars)
Upstream
$
178,712
$
73,524
$
163,087
$
68,410
Downstream
65,841
30,148
62,392
28,918
Chemical
24,081
10,071
22,197
9,319
Other
11,706
7,126
11,608
7,040
Total
$
280,340
$
120,869
$
259,284
$
113,687
In the Upstream segment, depreciation is on a unit-of-production basis, so depreciable life will vary by field. In
the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the
Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life.
Accumulated
depreciation and depletion totaled $159,471 million at the end of 2007 and $145,597 million at the end of 2006. Interest capitalized in 2007, 2006 and 2005 was $557 million, $530 million and $434 million, respectively.
Asset Retirement Obligations
The Corporation incurs retirement
obligations for its upstream 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 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:
9.
Accounting for Suspended Exploratory Well Costs
In accounting for suspended exploratory well costs, the Corporation utilizes
Financial Accounting Standards Board Staff Position FAS 19-1 (FSP 19-1), “Accounting for Suspended Well Costs.” FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), “Financial Accounting and Reporting by
Oil and Gas Producing Companies,” to permit the continued capitalization of exploratory well costs beyond one year after the well is completed if (a) the well found a sufficient quantity of reserves to justify its completion as a producing
well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.
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:
2007
2006
2005
(millions of dollars)
Balance beginning at January 1
$
1,305
$
1,139
$
1,070
Additions pending the determination of proved reserves
228
257
233
Charged to expense
(108
)
(54
)
(62
)
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
(82
)
(22
)
(82
)
Other
(52
)
(15
)
(20
)
Ending balance
$
1,291
$
1,305
$
1,139
Ending balance attributed to equity companies included above
$
3
$
17
$
2
Period end capitalized suspended exploratory well costs:
2007
2006
2005
(millions of dollars)
Capitalized for a period of one year or less
$
228
$
257
$
233
Capitalized for a period of between one and five years
566
566
485
Capitalized for a period of between five and ten years
255
213
167
Capitalized for a period of greater than ten years
242
269
254
Capitalized for a period greater than one year – subtotal
$
1,063
$
1,048
$
906
Total
$
1,291
$
1,305
$
1,139
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project.
The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a
period greater than 12 months.
2007
2006
2005
Number of projects with first capitalized well drilled in the preceding 12 months
4
13
16
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months
Of the 49 projects that have exploratory well costs capitalized for a period greater than 12 months as of
December 31, 2007, 29 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 20 projects are those with completed exploratory activity progressing toward development. The
table below provides additional detail for those 20 projects, which total $291 million.
Country/Project
Dec. 31,
2007
Years
Wells Drilled
Comment
(millions
of dollars)
Australia
– East
Pilchard
$9
2001
Gas field near Kipper/Tuna development, awaiting capacity in existing/planned
infrastructure.
Canada
–
Hibernia
36
2006
Progressing development plan and regulatory approvals for tieback to Hibernia gravity-based structure.
Indonesia
– Natuna
118
1981 - 1983
Intent to proceed to the next phase of development communicated to government in 2004; discussions with
government on near-term development work plans and contract terms are in progress; further technical evaluation and gas marketing activities continued to progress in 2007.
Kazakhstan
– Aktote
42
2003 - 2004
Development study under way to examine tieback to Kashagan field and/or potential development with
Kairan field that is still in the exploration phase.
Nigeria
–
Etoro-Isobo
9
2002
Offshore satellite development which will tie back to a planned production facility.
– Other (4 projects)
12
2001 - 2002
Actively pursuing development of several additional offshore satellite discoveries which will tie back
to existing/planned production facilities.
United Kingdom
– Carrack
West
8
2001
Planned tieback to Carrack production facility; awaiting capacity.
–
Phyllis
10
2004
Assessing co-development option with nearby 2005 Barbara discovery.
United States
– Point
Thomson
28
1977 - 1980
The Point Thomson Unit owners are progressing plans to put the unit into production. A project team
continues evaluating gas transportation alternatives. The 2006 order of the Alaska Department of Natural Resources terminating the Point Thomson Unit was reversed on appeal by order of the Alaska Superior Court.
Other
– Various (8 projects)
19
1979 - 2005
Projects primarily awaiting capacity in existing or planned infrastructure.
At December 31, 2007, 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 $9,916 million as indicated in the table. Estimated related rental income from
noncancelable subleases is $191 million.
Lease Payments
Under Minimum
Commitments
Related
Sublease Rental
Income
(millions of dollars)
2008
$
1,994
$
37
2009
1,917
32
2010
1,546
28
2011
1,130
24
2012
765
18
2013 and beyond
2,564
52
Total
$
9,916
$
191
Net rental expenses under both cancelable and noncancelable operating leases incurred during 2007, 2006 and 2005
were as follows:
2007
2006
2005
(millions of dollars)
Rental expense
$
3,367
$
3,576
$
2,966
Less sublease rental income
168
172
176
Net rental expense
$
3,199
$
3,404
$
2,790
11. Earnings Per Share
2007
2006
2005
Net income per common share
Net income
(millions of dollars)
$
40,610
$
39,500
$
36,130
Weighted average number of common shares outstanding
(millions of shares)
5,517
5,913
6,266
Net income per common share
(dollars)
$
7.36
$
6.68
$
5.76
Net income per common share – assuming dilution
Net income
(millions of dollars)
$
40,610
$
39,500
$
36,130
Weighted average number of common shares outstanding
(millions of shares)
5,517
5,913
6,266
Effect of employee stock-based awards
60
57
56
Weighted average number of common shares outstanding – assuming dilution
The fair value of financial instruments is determined by reference to various
market data and other valuation techniques as appropriate. Long-term debt is the only category of financial instruments whose fair value differs materially from the recorded book value. The estimated fair value of total long-term debt, including
capitalized lease obligations, at December 31, 2007, and 2006, was $7.9 billion and $7.2 billion, respectively, as compared to recorded book values of $7.2 billion and $6.6 billion.
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical
businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation
does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of
derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity.
The estimated fair value of derivatives outstanding and recorded on the balance sheet was a net receivable of $31 million at year-end 2007 and a net
payable of $64 million at year-end 2006. This is the amount that the Corporation would have received from, or paid to, third parties if these derivatives had been settled in the open market. The Corporation recognized a before-tax gain of $66
million and $397 million and a loss of $312 million related to derivatives during 2007, 2006 and 2005, respectively.
The fair value of
derivatives outstanding at year-end 2007 and gain recognized during the year are immaterial in relation to the Corporation’s year-end cash balance of $34.0 billion, total assets of $242.1 billion or net income for the year of $40.6 billion.
13. Long-Term Debt
At December 31, 2007, long-term debt consisted of $6,689 million due in U.S. dollars and $494 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 $318 million, which matures within one year and is included in current
liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2008, in millions of dollars, are: 2009 – $255, 2010 – $203, 2011 – $206 and 2012
– $2,246. At December 31, 2007, the Corporation’s unused long-term credit lines were not material.
Summarized long-term
borrowings at year-end 2007 and 2006 were as shown in the table below:
2007
2006
(millions of dollars)
Exxon Capital Corporation
6.125% Guaranteed notes due 2008
$
—
$
160
SeaRiver Maritime Financial Holdings, Inc.
(1)
Guaranteed debt securities due 2008-2011
(2)
39
52
Guaranteed deferred interest debentures due 2012
– Face value net of unamortized discount plus accrued interest
1,727
1,550
Mobil Services (Bahamas) Ltd.
Variable notes due 2035
(3)
972
972
Variable notes due 2034
(4)
311
311
Mobil Producing Nigeria Unlimited
(5)
Variable notes due 2012-2016
708
489
Esso (Thailand) Public Company Ltd.
(6)
Variable note due 2009-2012
326
—
Mobil Corporation
8.625% debentures due 2021
248
248
Industrial revenue bonds due 2012-2039
(7)
1,694
1,697
Other U.S. dollar obligations
(8)
629
786
Other foreign currency obligations
120
160
Capitalized lease obligations
(9)
409
220
Total long-term debt
$
7,183
$
6,645
(1)
Additional information is provided for this subsidiary on the following pages.
(2)
Average effective interest rate of 5.3% in 2007 and 5.1% in 2006.
(3)
Average effective interest rate of 5.3% in 2007 and 5.1% in 2006.
(4)
Average effective interest rate of 5.4% in 2007 and 5.1% in 2006.
(5)
Average effective interest rate of 8.8% in 2007 and 8.6% in 2006.
(6)
Average effective interest rate of 4.5% in 2007.
(7)
Average effective interest rate of 3.9% in 2007 and 3.7% in 2006.
(8)
Average effective interest rate of 6.6% in 2007 and 6.6% in 2006.
(9)
Average imputed interest rate of 7.3% in 2007 and 7.6% in 2006.
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil
Corporation has fully and unconditionally guaranteed the deferred interest debentures due 2012 ($1,727 million long-term debt at December 31, 2007) and the debt securities due 2008 to 2011 ($39 million long-term and $13 million short-term) of
SeaRiver Maritime Financial Holdings, Inc.
SeaRiver Maritime Financial Holdings, Inc. is a 100-percent-owned subsidiary of Exxon Mobil
Corporation.
The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for
SeaRiver Maritime Financial Holdings, Inc., as issuer, as an alternative to providing separate financial statements for the issuer. The accounts of Exxon Mobil Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the
equity method of accounting for investments in subsidiaries.
Exxon Mobil
Corporation
Parent
Guarantor
SeaRiver
Maritime
Financial
Holdings, Inc.
All Other
Subsidiaries
Consolidating
and
Eliminating
Adjustments
Consolidated
(millions of dollars)
Condensed consolidated statement of income for 12 months ended December 31, 2007
Revenues and other income
Sales and other operating revenue, including sales-based taxes
$
16,502
$
—
$
373,826
$
—
$
390,328
Income from equity affiliates
40,800
4
8,859
(40,762
)
8,901
Other income
488
—
4,835
—
5,323
Intercompany revenue
39,490
101
361,263
(400,854
)
—
Total revenues and other income
97,280
105
748,783
(441,616
)
404,552
Costs and other deductions
Crude oil and product purchases
38,260
—
535,973
(374,735
)
199,498
Production and manufacturing expenses
7,147
—
30,003
(5,265
)
31,885
Selling, general and administrative expenses
2,581
—
13,116
(807
)
14,890
Depreciation and depletion
1,661
—
10,589
—
12,250
Exploration expenses, including dry holes
276
—
1,193
—
1,469
Interest expense
5,997
201
14,601
(20,399
)
400
Sales-based taxes
—
—
31,728
—
31,728
Other taxes and duties
48
—
40,905
—
40,953
Income applicable to minority and preferred interests
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil
Corporation
Parent
Guarantor
SeaRiver
Maritime
Financial
Holdings, Inc.
All Other
Subsidiaries
Consolidating
and
Eliminating
Adjustments
Consolidated
(millions of dollars)
Condensed consolidated statement of cash flows for 12 months ended December 31, 2005
Cash provided by/(used in) operating activities
$
11,538
$
129
$
42,099
$
(5,628
)
$
48,138
Cash flows from investing activities
Additions to property, plant and equipment
(1,296
)
—
(12,543
)
—
(13,839
)
Sales of long-term assets
314
—
5,722
—
6,036
Decrease/(increase) in restricted cash and cash equivalents
—
—
—
—
—
Net intercompany investing
15,483
(173
)
(15,545
)
235
—
All other investing, net
1
—
(2,468
)
—
(2,467
)
Net cash provided by/(used in) investing activities
14,502
(173
)
(24,834
)
235
(10,270
)
Cash flows from financing activities
Additions to short- and long-term debt
—
—
572
—
572
Reductions in short- and long-term debt
—
(10
)
(758
)
—
(768
)
Additions/(reductions) in debt with less than 90-day maturity
446
—
(1,752
)
—
(1,306
)
Cash dividends
(7,185
)
—
(5,628
)
5,628
(7,185
)
Common stock acquired
(18,221
)
—
—
—
(18,221
)
Net intercompany financing activity
—
(21
)
181
(160
)
—
All other financing, net
941
75
(974
)
(75
)
(33
)
Net cash provided by/(used in) financing activities
(24,019
)
44
(8,359
)
5,393
(26,941
)
Effects of exchange rate changes on cash
—
—
(787
)
—
(787
)
Increase/(decrease) in cash and cash equivalents
$
2,021
$
—
$
8,119
$
—
$
10,140
14. 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. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or 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 2007, remaining shares available for award under the 2003 Incentive Program were
170,695 thousand.
As under earlier programs, 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. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were granted prior to 2002.
Long-term incentive awards totaling 10,226 thousand, 10,187 thousand and 11,071 thousand shares of
restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2007, 2006 and 2005, respectively. These shares are issued to employees from treasury stock. The total compensation expense is recognized over the
requisite service period. 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 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 in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to
certain senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.
The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in
conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.
In 2002, the Corporation
began issuing restricted stock as share-based compensation in lieu of stock options. Compensation expense for these awards is based on the price of the stock at the date of grant and has been recognized in income over the requisite service period,
which is the same method of accounting as under FAS 123R. Prior to 2002, the Corporation issued stock options as share-based compensation and since these awards vested prior to the effective date of FAS 123R, they continue to be accounted for by the
method prescribed in APB 25, “Accounting for Stock Issued to Employees.” Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the
market price of the stock and the exercise price of the options) on the date of grant. Since these two prices were the same on the date of grant, no compensation expense has been recognized in income for these awards.
The following table summarizes information about restricted stock and restricted stock units, including those shares from former Mobil plans, for the
year ended December 31, 2007.
Restricted Stock and Units Outstanding
Shares
Weighted
Average
Grant-Date
Fair Value
per Share
(thousands)
Issued and outstanding at January 1, 2007
36,124
$
47.30
2006 award issued in 2007
10,167
$
73.47
Vested
(6,795
)
$
46.02
Forfeited
(281
)
$
53.57
Issued and outstanding at December 31, 2007
39,215
$
54.26
Grant Value of Restricted Stock and Units
2007
2006
2005
Grant price
$
87.14
$
73.47
$
58.43
(millions of dollars)
Value at date of grant:
Restricted stock and units settled in stock
$
827
$
704
$
611
Units settled in cash
64
44
36
Total value
$
891
$
748
$
647
As of December 31, 2007, there was $1,892 million of unrecognized compensation cost related to the nonvested
restricted awards. This cost is expected to be recognized over a weighted-average period of 4.7 years. The compensation cost charged against income for the restricted stock and restricted units was $590 million, $527 million and $387 million for
2007, 2006 and 2005, respectively. The income tax benefit recognized in income related to this compensation expense was $81 million,
$72 million and $69 million for the same periods, respectively. The fair value of shares and units vested in
2007, 2006 and 2005 was $581 million, $310 million and $288 million, respectively. Cash payments of $29 million, $18 million and $15 million for vested restricted stock units settled in cash were made in 2007, 2006 and 2005, respectively.
Changes that occurred in stock options in 2007 are summarized below (shares in thousands):
2007
Stock Options
Shares
Avg. Exercise
Price
Weighted Average
Remaining Contractual Term
Outstanding at January 1
110,487
$
38.86
Exercised
(30,168
)
$
35.88
Forfeited
(30
)
$
37.11
Outstanding at December 31
80,289
$
39.98
2.7 Years
Exercisable at December 31
80,289
$
39.98
2.7 Years
No compensation expense was recognized for stock options in 2007, 2006 and 2005, as all remaining outstanding
stock options were granted prior to 2002 and are fully vested. Cash received from stock option exercises was $1,079 million, $1,173 million and $941 million for 2007, 2006 and 2005, respectively. The cash tax benefit realized for the options
exercised was $304 million, $416 million and $295 million for 2007, 2006 and 2005, respectively. The aggregate intrinsic value of stock options exercised in 2007, 2006 and 2005 was $1,359 million, $1,304 million and $954 million, respectively. The
intrinsic value for the balance of outstanding stock options at December 31, 2007, was $4,312 million.
15. 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. 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 materially adverse effect upon the Corporation’s operations or financial condition.
A number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its
subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims have been resolved and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994.
The first judgment from the United States District Court for the District of Alaska in the amount of $5 billion was vacated by the United States Court of Appeals for the Ninth Circuit as being excessive under the Constitution. The second judgment in
the amount of $4 billion was vacated by the Ninth Circuit panel without argument and sent back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in
Campbell v. State Farm
. The most recent District
Court judgment for punitive damages was for $4.5 billion plus interest and was entered in January 2004. The Corporation posted a $5.4 billion letter of credit. ExxonMobil and the plaintiffs appealed this decision to the Ninth Circuit, which ruled on
December 22, 2006, that the award be reduced to $2.5 billion. On January 12, 2007, ExxonMobil petitioned the Ninth Circuit Court of Appeals for a rehearing en banc of its appeal. On May 23, 2007, with two dissenting opinions, the
Ninth Circuit determined not to re-hear ExxonMobil’s appeal before the full court. ExxonMobil filed a petition for writ of certiorari to the U.S. Supreme Court on August 20, 2007. On October 29, 2007, the U.S. Supreme Court granted
ExxonMobil’s petition for a writ of certiorari. Oral argument was held on February 27, 2008. While it is reasonably possible that a liability for punitive damages may have been incurred from the Exxon Valdez grounding, it is not possible
to predict the ultimate outcome or to reasonably estimate any such potential liability.
In December 2000,
a jury in the 15th Judicial Circuit Court of Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of
Exxon Corporation v. State of Alabama, et al.
The verdict was upheld by the trial court in May 2001. In December 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and in November 2003, a state
district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. In March 2004, the district court judge reduced the
amount of punitive damages to $3.5 billion. ExxonMobil appealed the decision to the Alabama Supreme Court. On November 1, 2007, the Alabama Supreme Court reversed the trial court’s fraud judgment and instructed the district court to enter
judgment for ExxonMobil on the fraud claim, eliminating the punitive damage award. The Court also ruled in ExxonMobil’s favor on some of the disputed lease issues, reducing the compensatory award to $52 million plus interest. Following the
Alabama Supreme Court’s decision, an appeal bond was canceled and the collateral was subsequently released.
In 2001, a Louisiana state court jury awarded compensatory damages of $56 million and punitive damages of
$1 billion to a landowner for damage caused by a third party that leased the property from the landowner. The third party provided pipe cleaning and storage services for the Corporation and other entities. The Louisiana Fourth Circuit Court of
Appeals reduced the punitive damage award to $112 million in 2005. The Corporation appealed this decision to the Louisiana Supreme Court which, in March 2006, refused to hear the appeal. ExxonMobil has fully accrued and paid the compensatory and
punitive damage awards. The Corporation appealed the punitive damage award to the U.S. Supreme Court, which on February 26, 2007, vacated the judgment and remanded the case to the Louisiana Fourth Circuit Court of Appeals for reconsideration in
light of the recent U.S. Supreme Court decision in
Williams v. Phillip Morris USA
. On August 8, 2007, the Fourth Circuit issued its decision on remand and declined to reduce the punitive damage award. On November 16, 2007, the
Louisiana Supreme Court denied ExxonMobil’s writ for review of the Fourth Circuit’s decision. ExxonMobil has appealed to the U.S. Supreme Court.
Other Contingencies
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2007, for
$5,148 million, primarily relating to guarantees for notes, loans and performance under contracts. Included in this amount were guarantees by consolidated affiliates of $4,591 million, representing ExxonMobil’s share of obligations of certain
equity companies.
Dec. 31, 2007
Equity
Company
Obligations
Other
Third-Party
Obligations
Total
(millions of dollars)
Total guarantees
$
4,591
$
557
$
5,148
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase
commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligations, as defined by
accounting standards, are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.
Payments Due by Period
2008
2009-
2012
2013
and
Beyond
Total
(millions of dollars)
Unconditional purchase obligations
(1)
$
490
$
1,497
$
778
$
2,765
(1)
Undiscounted obligations of $2,765 million mainly pertain to pipeline throughput agreements and include $1,847 million of obligations to equity companies. The present value of
these commitments, which excludes imputed interest of $562 million, totaled $2,203 million.
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 PdVSA, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
To date, discussions with Venezuelan authorities have not resulted in an agreement on the amount of compensation to be
paid to ExxonMobil. On September 6, 2007, ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. ExxonMobil has also filed an arbitration under the rules of the International Chamber of
Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be
reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition. At the time the assets were expropriated, ExxonMobil’s remaining net book
investment in Cerro Negro producing assets was about $750 million.
The benefit obligations and plan assets associated with the Corporation’s
principal benefit plans are measured on December 31.
Pension Benefits
Other Postretirement
Benefits
U.S.
Non-U.S.
2007
2006
2007
2006
2007
2006
(percent)
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate
6.25
6.00
5.40
4.70
6.25
6.00
Long-term rate of compensation increase
5.00
4.50
4.50
4.20
5.00
4.50
(millions of dollars)
Change in benefit obligation
Benefit obligation at January 1
$
11,305
$
11,181
$
20,956
$
19,310
$
6,843
$
5,370
Service cost
360
335
451
428
109
76
Interest cost
687
632
1,011
911
403
308
Actuarial loss/(gain)
896
484
(665
)
(38
)
(275
)
1,440
Benefits paid
(1) (2)
(1,091
)
(1,329
)
(1,197
)
(1,153
)
(416
)
(419
)
Foreign exchange rate changes
—
—
1,937
1,424
73
—
Plan amendments, other
(95
)
2
(18
)
74
91
68
Benefit obligation at December 31
$
12,062
$
11,305
$
22,475
$
20,956
$
6,828
$
6,843
Accumulated benefit obligation at December 31
$
10,244
$
9,811
$
20,151
$
18,883
$
—
$
—
(1)
Benefit payments for funded and unfunded plans.
(2)
For 2007 and 2006, other postretirement benefits paid are net of $19 million and $20 million Medicare subsidy receipts, respectively.
For U.S. plans, the discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit
payments. For major non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, both of which are constructed using high-quality,
local-currency-denominated bonds.
The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend
rate of 7.5 percent for 2008 that declines to 4.5 percent by 2014. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $54 million and the postretirement benefit obligation by $564 million.
A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $44 million and the post-retirement benefit obligation by $468 million.
The Corporation offers a Medicare supplement plan to Medicare-eligible retirees that provides prescription drug benefits. The Medicare Prescription Drug,
Improvement and Modernization Act of 2003 provides a federal subsidy to employers sponsoring retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Corporation believes that its
Medicare supplement plan is at least actuarially equivalent to Medicare Part D.
The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation.
As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined benefit pension
obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
In 2007 and 2006, the Corporation contributed $800 million and $2,383 million, respectively, to the U.S. funded pension plan, approximately the maximum
tax-deductible amount. As a result, year-end 2007 U.S. pension assets of $10,617 million were $1,493 million greater than the funded plan accumulated benefit obligation of $9,124 million.
Pension Benefits
U.S.
Non-U.S.
2007
2006
2007
2006
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans
$
(64
)
$
(254
)
$
192
$
(1,479
)
Unfunded plans
(1,381
)
(1,299
)
(5,475
)
(5,090
)
Total
$
(1,445
)
$
(1,553
)
$
(5,283
)
$
(6,569
)
Effective December 31, 2006, Exxon Mobil Corporation implemented FASB Statement No. 158,
“Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which 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
Benefits
U.S.
Non-U.S.
2007
2006
2007
2006
2007
2006
(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
(1)
$
(1,445
)
$
(1,553
)
$
(5,283
)
$
(6,569
)
$
(6,169
)
$
(6,342
)
Amounts recorded in the consolidated balance sheet consist of:
Other assets
$
43
$
36
$
1,168
$
196
$
—
$
—
Current liabilities
(177
)
(160
)
(329
)
(294
)
(324
)
(311
)
Postretirement benefits reserves
(1,311
)
(1,429
)
(6,122
)
(6,471
)
(5,845
)
(6,031
)
Total recorded
$
(1,445
)
$
(1,553
)
$
(5,283
)
$
(6,569
)
$
(6,169
)
$
(6,342
)
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)
$
2,378
$
2,044
$
3,520
$
3,838
$
2,346
$
2,831
Prior service cost
3
121
810
780
326
401
Total recorded in accumulated other comprehensive income
$
2,381
$
2,165
$
4,330
$
4,618
$
2,672
$
3,232
(1)
Fair value of assets less benefit obligation shown on the preceding page.
The long-term expected rate of return on funded assets for each plan is established 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 and the long-term return assumption for each asset class. The majority of pension assets are invested in equities, as illustrated in the table below, which shows asset allocation.
Pension Benefits
Other Postretirement
Benefits
U.S.
Non-U.S.
2007
2006
2007
2006
2007
2006
(percent)
Funded benefit plan asset allocation
Equity securities
75
%
75
%
65
%
69
%
75
%
75
%
Debt securities
25
25
30
27
25
25
Other
—
—
5
4
—
—
Total
100
%
100
%
100
%
100
%
100
%
100
%
The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment
of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Corporation primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while
minimizing costs. The funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity
securities of 75 percent for the U.S. benefit plans and 64 percent for non-U.S. plans reflects the long-term nature of the liability. The balance of the funds is largely targeted to debt securities.
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.
2007
2006
2007
2006
(millions of dollars)
For
funded
pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation
$
—
$
4
$
2,697
$
8,971
Accumulated benefit obligation
—
3
2,527
8,322
Fair value of plan assets
—
2
1,919
7,265
For
unfunded
pension plans:
Projected benefit obligation
$
1,381
$
1,299
$
5,475
$
5,090
Accumulated benefit obligation
1,120
1,120
4,827
4,502
Pension Benefits
Other
Postretirement
Benefits
U.S.
Non-U.S.
(millions of dollars)
Estimated 2008 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain)
(1)
$
382
$
311
$
203
Prior service cost
(2)
(2
)
97
76
(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 FAS 87 and FAS 106.
17. 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 assess its performance; and (3) for which discrete financial information is available.
Earnings after income tax include special items, and transfers are at estimated market prices. There were no special items in 2007. After-tax earnings in
2006 included a $410 million special gain in the corporate and financing segment from the recognition of tax benefits related to historical investments in non-U.S. assets. Special items included in 2005 after-tax earnings are a $1,620 million gain
in Non-U.S. Upstream for the restructuring of a Dutch gas equity company, a $390 million gain in Non-U.S. Chemical relating to joint venture litigation, gains of $310 million and $150 million in Non-U.S. Downstream and Non-U.S. Chemical,
respectively, for the Sinopec share sale and a charge of $200 million in U.S. Downstream relating to the Allapattah lawsuit provision.
Interest expense includes non-debt-related interest expense of $290 million, $535 million and $369 million in 2007, 2006 and 2005, respectively. The decrease of $245 million in 2007 and the increase of $166 million in 2006 primarily reflect
changes in tax-related interest.
In corporate and financing activities, interest revenue relates to interest earned on cash deposits and
marketable securities.
Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005. Includes $30,810 million for
purchases/sales contracts with the same counterparty for 2005. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net
income. See note 1, Summary of Accounting Policies.
All other taxes and duties include taxes reported in production and manufacturing and selling, general and
administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits for the effect of changes in tax laws and rates of $258 million in 2007, $169 million in 2006 and $199 million in 2005.
Income taxes (charged)/credited directly to shareholders’ equity were:
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent
for 2007, 2006 and 2005, is as follows:
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized
for financial reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the
following at December 31:
Tax effects of temporary differences for:
2007
2006
(millions of dollars)
Depreciation
$
18,810
$
17,518
Intangible development costs
4,890
4,742
Capitalized interest
2,575
2,499
Other liabilities
3,955
3,240
Total deferred tax liabilities
$
30,230
$
27,999
Pension and other postretirement benefits
$
(3,837
)
$
(4,135
)
Tax loss carryforwards
(2,162
)
(2,002
)
Other assets
(5,848
)
(4,894
)
Total deferred tax assets
$
(11,847
)
$
(11,031
)
Asset valuation allowances
637
657
Net deferred tax liabilities
$
19,020
$
17,625
Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax
(assets) and liabilities are classified as current or long term consistent with the classification of the related temporary difference – separately by tax jurisdiction.
Balance sheet classification
2007
2006
(millions of dollars)
Prepaid taxes and expenses
$
(2,497
)
$
(1,636
)
Other assets, including intangibles, net
(1,451
)
(1,656
)
Accounts payable and accrued liabilities
69
66
Deferred income tax liabilities
22,899
20,851
Net deferred tax liabilities
$
19,020
$
17,625
The Corporation had $56 billion of indefinitely reinvested, undistributed earnings from subsidiary companies
outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.
Unrecognized Tax Benefits
The Corporation is subject to income taxation in many jurisdictions around the world. The total amounts of unrecognized tax benefits at January 1, 2007, and
December 31, 2007, are shown in the following table. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. Accordingly, it is difficult to predict
the timing of resolution for individual tax positions. However, the Corporation does not anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease in the next 12 months. Given the long time periods
involved in resolving individual tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.
The following table summarizes the movement in uncertain tax benefits from January 1 to December 31, 2007. The unrecognized tax benefits are
shown on both a gross basis and a net basis, reflecting the impact of funds placed on deposit with tax authorities. Such deposits do not acknowledge agreement with the tax authorities’ positions, but prevent further interest accretion on
potential tax assessments. For balance sheet reporting, the Corporation reports unrecognized tax benefits net of such deposits where there is a legal right and intent to offset under the local tax law.
Gross
Unrecognized
Tax Benefits
Deposits
Net
Unrecognized
Tax Benefits
(millions of dollars)
January 1, 2007, balance
$
4,583
$
(879
)
$
3,704
Additions based on current year tax positions
832
832
Additions for prior years’ tax positions
463
463
Reductions for prior years’ tax positions
(609
)
(609
)
Reductions due to a lapse of the statute of limitations
(84
)
(84
)
Settlements with tax authorities
(25
)
(25
)
Foreign exchange effects/change in deposit balance
72
109
181
December 31, 2007, balance
$
5,232
$
(770
)
$
4,462
The additions and reductions in unrecognized tax benefits shown above include effects related to net income and
shareholders’ equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2007 changes in unrecognized tax benefits did not have a material
effect on the Corporation’s net income or cash flow.
The following table summarizes the tax years that remain subject to examination
by major tax jurisdiction:
Country of Operation
Open Tax Years
Abu Dhabi
2000 - 2007
Angola
2002 - 2007
Australia
2000 - 2007
Canada
1990 - 2007
Equatorial Guinea
2004 - 2007
Germany
1998 - 2007
Japan
2002 - 2007
Malaysia
1983 - 2007
Nigeria
1998 - 2007
Norway
1993 - 2007
United Kingdom
2003 - 2007
United States
1989 - 2007
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 approximately $128 million in interest expense
on income tax reserves in 2007 and had a related interest payable of $597 million at December 31, 2007.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(unaudited)
The results of operations
for producing activities shown below are presented in accordance with Statement of Financial Accounting Standards No. 69. As such, they do not include earnings from other activities that ExxonMobil includes in the Upstream function such as oil
and gas transportation operations, oil sands operations, LNG liquefaction and transportation operations, coal and power operations, technical services agreements, other nonoperating activities and adjustments for minority interests. These excluded
amounts for both consolidated and equity companies totaled $2,271 million in 2007, $2,431 million in 2006 and $3,546 million in 2005.
Results of Operations
United
States
Canada/
South America
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
(millions of dollars)
2007 – Revenue
Sales to third parties
$
3,677
$
3,720
$
7,282
$
807
$
3,363
$
678
$
19,527
Transfers
6,554
2,783
9,780
17,048
7,276
2,087
45,528
$
10,231
$
6,503
$
17,062
$
17,855
$
10,639
$
2,765
$
65,055
Production costs excluding taxes
1,827
1,492
2,859
1,180
961
243
8,562
Exploration expenses
280
264
164
470
226
67
1,471
Depreciation and depletion
1,377
1,121
2,441
2,101
763
453
8,256
Taxes other than income
1,313
111
718
1,599
2,067
1
5,809
Related income tax
2,429
1,041
7,236
7,263
4,105
598
22,672
Results of producing activities for consolidated subsidiaries
$
3,005
$
2,474
$
3,644
$
5,242
$
2,517
$
1,403
$
18,285
Proportional interest in results of producing activities of equity companies
$
1,342
$
—
$
1,465
$
—
$
2,138
$
996
$
5,941
2006 – Revenue
Sales to third parties
$
4,027
$
4,390
$
9,382
$
1,145
$
4,393
$
533
$
23,870
Transfers
6,250
2,638
8,607
16,108
4,900
580
39,083
$
10,277
$
7,028
$
17,989
$
17,253
$
9,293
$
1,113
$
62,953
Production costs excluding taxes
1,916
1,410
2,290
965
824
118
7,523
Exploration expenses
245
172
161
330
157
116
1,181
Depreciation and depletion
1,155
1,023
2,166
2,096
674
305
7,419
Taxes other than income
802
139
846
1,612
2,652
1
6,052
Related income tax
2,711
1,143
8,032
6,878
2,820
217
21,801
Results of producing activities for consolidated subsidiaries
$
3,448
$
3,141
$
4,494
$
5,372
$
2,166
$
356
$
18,977
Proportional interest in results of producing activities of equity companies
$
1,236
$
—
$
1,164
$
—
$
1,555
$
867
$
4,822
2005 – Revenue
Sales to third parties
$
4,842
$
3,728
$
8,383
$
40
$
2,357
$
357
$
19,707
Transfers
6,277
3,582
7,040
12,293
3,143
279
32,614
$
11,119
$
7,310
$
15,423
$
12,333
$
5,500
$
636
$
52,321
Production costs excluding taxes
1,367
1,370
2,174
840
567
123
6,441
Exploration expenses
158
137
64
310
122
164
955
Depreciation and depletion
1,181
1,041
2,133
1,319
666
137
6,477
Taxes other than income
738
56
690
1,158
839
2
3,483
Related income tax
3,138
1,641
6,572
5,143
1,313
111
17,918
Results of producing activities for consolidated subsidiaries
$
4,537
$
3,065
$
3,790
$
3,563
$
1,993
$
99
$
17,047
Proportional interest in results of producing activities of equity companies
Average sales 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 proved reserves table of this
report. The volumes for natural gas used for this calculation are the production volumes of natural gas available for sale and thus are different than those shown in the proved reserves table of this report due to volumes consumed or flared. The
volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.
Average sales prices and production costs per
unit of production – consolidated subsidiaries
United
States
Canada/
South America
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
During 2007
Average sales prices
Crude oil and NGL, per barrel
$
62.35
$
50.41
$
68.01
$
70.00
$
69.58
$
69.15
$
66.02
Natural gas, per thousand cubic feet
5.93
5.77
6.22
2.26
3.54
1.79
5.29
Average production costs, per barrel
(1)
9.03
10.38
9.12
4.48
4.09
5.79
7.14
During 2006
Average sales prices
Crude oil and NGL, per barrel
$
55.13
$
47.70
$
59.90
$
61.26
$
62.02
$
57.38
$
58.34
Natural gas, per thousand cubic feet
6.22
5.81
7.48
—
3.87
2.31
6.08
Average production costs, per barrel
(1)
8.78
8.55
6.64
3.39
3.90
5.45
6.04
During 2005
Average sales prices
Crude oil and NGL, per barrel
$
46.11
$
38.68
$
50.32
$
51.21
$
52.89
$
51.65
$
48.23
Natural gas, per thousand cubic feet
7.30
6.90
5.64
—
4.16
1.35
5.96
Average production costs, per barrel
(1)
5.56
7.36
5.95
3.46
3.85
9.49
5.36
(1)
Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil-equivalent.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(unaudited)
Oil and Gas Exploration and Production Costs
The amounts shown for
net capitalized costs of consolidated subsidiaries are $6,381 million less at year-end 2007 and $5,463 million less at year-end 2006 than the amounts reported as investments in property, plant and equipment for the Upstream in note 8. This is due to
the exclusion from capitalized costs of certain transportation and research assets and assets relating to the oil sands and LNG operations, all as required by Statement of Financial Accounting Standards No. 19.
Capitalized Costs
United
States
Canada/
South America
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
(millions of dollars)
As of December 31, 2007
Property (acreage) costs – Proved
$
3,227
$
4,102
$
272
$
200
$
1,172
$
521
$
9,494
– Unproved
556
524
30
540
1,142
45
2,837
Total property costs
$
3,783
$
4,626
$
302
$
740
$
2,314
$
566
$
12,331
Producing assets
35,830
15,370
48,673
19,633
17,302
2,796
139,604
Support facilities
694
269
619
461
1,186
428
3,657
Incomplete construction
2,406
950
891
3,576
3,133
3,040
13,996
Total capitalized costs
$
42,713
$
21,215
$
50,485
$
24,410
$
23,935
$
6,830
$
169,588
Accumulated depreciation and depletion
27,427
13,529
36,520
9,261
14,674
1,034
102,445
Net capitalized costs for consolidated subsidiaries
$
15,286
$
7,686
$
13,965
$
15,149
$
9,261
$
5,796
$
67,143
Proportional interest of net capitalized costs of equity companies
$
1,662
$
—
$
1,461
$
—
$
1,413
$
3,346
$
7,882
As of December 31, 2006
Property (acreage) costs – Proved
$
3,260
$
3,532
$
277
$
200
$
1,164
$
512
$
8,945
– Unproved
574
429
31
523
1,070
99
2,726
Total property costs
$
3,834
$
3,961
$
308
$
723
$
2,234
$
611
$
11,671
Producing assets
34,852
12,800
44,719
16,748
16,295
2,324
127,738
Support facilities
740
257
581
442
1,158
308
3,486
Incomplete construction
2,273
893
1,439
3,533
1,537
2,605
12,280
Total capitalized costs
$
41,699
$
17,911
$
47,047
$
21,446
$
21,224
$
5,848
$
155,175
Accumulated depreciation and depletion
26,696
10,780
33,302
7,166
13,649
635
92,228
Net capitalized costs for consolidated subsidiaries
$
15,003
$
7,131
$
13,745
$
14,280
$
7,575
$
5,213
$
62,947
Proportional interest of net capitalized costs of equity companies
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 2007 were $12,075 million, down $938
million from 2006, due primarily to lower development and property acquisition costs. 2006 costs were $13,013 million, up $2,229 million from 2005, due primarily to higher development and property acquisition costs.
Costs incurred in property acquisitions,
exploration and development activities
United
States
Canada/
South America
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
(millions of dollars)
During 2007
Property acquisition costs – Proved
$
24
$
—
$
—
$
3
$
—
$
10
$
37
– Unproved
39
93
—
10
15
—
157
Exploration costs
375
222
201
584
261
80
1,723
Development costs
1,558
645
1,826
2,846
2,156
1,127
10,158
Total costs incurred for consolidated subsidiaries
$
1,996
$
960
$
2,027
$
3,443
$
2,432
$
1,217
$
12,075
Proportional interest of costs incurred of equity companies
$
303
$
—
$
218
$
1
$
249
$
414
$
1,185
During 2006
Property acquisition costs – Proved
$
11
$
—
$
6
$
—
$
206
$
11
$
234
– Unproved
43
—
5
16
199
—
263
Exploration costs
380
225
178
518
219
126
1,646
Development costs
1,555
850
2,443
3,433
1,475
1,114
10,870
Total costs incurred for consolidated subsidiaries
$
1,989
$
1,075
$
2,632
$
3,967
$
2,099
$
1,251
$
13,013
Proportional interest of costs incurred of equity companies
$
285
$
—
$
241
$
—
$
243
$
351
$
1,120
During 2005
Property acquisition costs – Proved
$
—
$
—
$
—
$
—
$
—
$
174
$
174
– Unproved
11
18
—
53
41
156
279
Exploration costs
286
121
133
507
171
159
1,377
Development costs
1,426
722
1,302
3,189
541
1,774
8,954
Total costs incurred for consolidated subsidiaries
$
1,723
$
861
$
1,435
$
3,749
$
753
$
2,263
$
10,784
Proportional interest of costs incurred of equity companies
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(unaudited)
Oil and Gas Reserves
The following information describes changes
during the years and balances of proved oil and gas reserves at year-end 2005, 2006 and 2007.
The definitions used are in accordance with
the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X, paragraphs (2) through (2)iii, (3) and (4).
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon
future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.
The year-end reserves volumes as well as the reserves change categories shown in the following tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating
unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and
to enhance comparability between companies.
Regulations preclude the Corporation from showing in this document, however, the reserves that
are calculated in a manner that is consistent with the basis that the Corporation uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual
adjustments are required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where production from individual projects often spans multiple
decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.
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 year-end prices and costs that are used in the determination of reserves.
This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.
Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage
of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants.
These liquids are included in net proved reserves of crude oil and natural gas liquids.
In the proved reserves tables, consolidated
reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.
Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal
terms in the agreement. The percentage of conventional liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2007 that were associated with production sharing contract arrangements was 18 percent of
liquids, 13 percent of natural gas and 15 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those volumes that are expected to be
recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells.
Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves.
The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes.
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2005
2,593
1,105
1,014
2,444
515
724
8,395
Revisions
(256
)
336
17
(8
)
78
(27
)
140
Purchases
—
—
—
—
—
93
93
Sales
(96
)
(49
)
(1
)
—
(11
)
(70
)
(227
)
Improved recovery
2
—
3
—
—
—
5
Extensions and discoveries
6
16
47
120
—
—
189
Production
(136
)
(125
)
(197
)
(244
)
(67
)
(13
)
(782
)
December 31, 2005
2,113
1,283
883
2,312
515
707
7,813
Revisions
(99
)
247
50
24
19
105
346
Purchases
4
—
8
—
734
—
746
Sales
(41
)
(27
)
(18
)
—
—
—
(86
)
Improved recovery
21
—
—
—
—
—
21
Extensions and discoveries
2
—
13
38
133
—
186
Production
(116
)
(108
)
(188
)
(285
)
(114
)
(21
)
(832
)
December 31, 2006
1,884
1,395
748
2,089
1,287
791
8,194
Revisions
76
15
89
99
342
(38
)
583
Purchases
—
—
—
—
—
—
—
Sales
(8
)
(426
)
(2)
(1
)
—
—
—
(435
)
Improved recovery
8
5
8
4
—
—
25
Extensions and discoveries
2
45
2
128
1
—
178
Production
(111
)
(95
)
(173
)
(262
)
(120
)
(40
)
(801
)
December 31, 2007
1,851
939
673
2,058
1,510
713
7,744
Proportional interest in proved reserves of equity companies
End of year 2005
413
—
11
—
1,381
873
2,678
End of year 2006
391
—
12
—
1,412
841
2,656
End of year 2007
374
—
26
—
1,428
808
2,636
Proved developed reserves, included above, as of December 31, 2005
Consolidated subsidiaries
1,680
834
656
1,218
464
55
4,907
Equity companies
326
—
9
—
725
574
1,634
Proved developed reserves, included above, as of December 31, 2006
Consolidated subsidiaries
1,466
902
557
1,279
1,090
108
5,402
Equity companies
311
—
11
—
630
544
1,496
Proved developed reserves, included above, as of December 31, 2007
Consolidated subsidiaries
1,327
682
518
1,202
1,127
91
4,947
Equity companies
299
—
8
—
670
511
1,488
(1)
Includes total proved reserves attributable to Imperial Oil Limited of 634 million barrels in 2005, 812 million barrels in 2006 and 799 million barrels in 2007, as
well as proved developed reserves of 449 million barrels in 2005, 572 million barrels in 2006 and 565 million barrels in 2007, in which there is a 30.4 percent minority interest.
(2)
Includes 425 million barrels of proved reserves in Venezuela which were expropriated. See note 15, Litigation and Other Contingencies.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(unaudited)
Oil and Gas Reserves
(continued)
Natural Gas
United
States
Canada/
South America
(1)
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
(billions of cubic feet)
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2005
12,329
2,652
9,185
771
6,391
515
31,843
Revisions
1,943
83
242
35
1,402
(18
)
3,687
Purchases
—
—
—
—
—
53
53
Sales
(105
)
(25
)
(73
)
—
—
(26
)
(229
)
Improved recovery
—
—
—
—
—
—
—
Extensions and discoveries
289
26
116
57
32
300
820
Production
(764
)
(412
)
(1,072
)
(22
)
(546
)
(3
)
(2,819
)
December 31, 2005
13,692
2,324
8,398
841
7,279
821
33,355
Revisions
(1,179
)
73
(457
)
170
414
(20
)
(999
)
Purchases
19
—
38
—
—
—
57
Sales
(57
)
(44
)
(3
)
—
—
—
(104
)
Improved recovery
12
—
—
—
—
—
12
Extensions and discoveries
268
10
117
1
2,534
—
2,930
Production
(706
)
(379
)
(1,004
)
(26
)
(644
)
(12
)
(2,771
)
December 31, 2006
12,049
1,984
7,089
986
9,583
789
32,480
Revisions
1,566
124
375
(22
)
813
(43
)
2,813
Purchases
9
—
—
—
—
—
9
Sales
(19
)
(231
)
(2)
(70
)
—
—
—
(320
)
Improved recovery
—
1
—
—
—
—
1
Extensions and discoveries
208
8
13
81
—
—
310
Production
(641
)
(327
)
(895
)
(39
)
(762
)
(19
)
(2,683
)
December 31, 2007
13,172
1,559
6,512
1,006
9,634
727
32,610
Proportional interest in proved reserves of equity companies
End of year 2005
136
—
13,024
—
19,119
1,273
33,552
End of year 2006
131
—
12,551
—
21,184
1,214
35,080
End of year 2007
125
—
12,341
—
21,733
1,453
35,652
(1)
Includes total proved reserves attributable to Imperial Oil Limited of 747 billion cubic feet in 2005, 710 billion cubic feet in 2006 and 635 billion cubic feet in 2007, in which
there is a 30.4 percent minority interest.
(2)
Includes 219 billion cubic feet of proved reserves in Venezuela which were expropriated. See note 15, Litigation and Other Contingencies.
Proved developed reserves, included above, as of December 31, 2005
Consolidated subsidiaries
10,386
1,840
6,332
376
6,067
227
25,228
Equity companies
113
—
10,226
—
7,276
835
18,450
Proved developed reserves, included above, as of December 31, 2006
Consolidated subsidiaries
9,280
1,628
5,346
823
5,882
447
23,406
Equity companies
109
—
9,985
—
7,906
811
18,811
Proved developed reserves, included above, as of December 31, 2007
Consolidated subsidiaries
8,373
1,303
5,064
773
5,570
395
21,478
Equity companies
104
—
9,679
—
8,702
757
19,242
(1)
Includes proved developed reserves attributable to Imperial Oil Limited of 643 billion cubic feet in 2005, 608 billion cubic feet in 2006 and 539 billion cubic feet in 2007, in
which there is a 30.4 percent minority interest.
INFORMATION ON CANADIAN OIL SANDS PROVEN RESERVES NOT INCLUDED ABOVE
In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven oil sands reserves in Canada associated with the Syncrude project. For internal management purposes, ExxonMobil views these
reserves and their development as an integral part of total upstream operations. However, for financial reporting purposes, these reserves are required to be reported separately from the oil and gas reserves.
The oil sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is on
the following page.
Oil Sands Reserves
Canada
(1)
(millions of barrels)
At December 31, 2005
738
At December 31, 2006
718
At December 31, 2007
694
(1)
Oil sands proven reserves are attributable to Imperial Oil Limited, in which there is a 30.4 percent minority interest.
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
(unaudited)
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 year-end prices, 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 year-end prices, which
represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change.
Standardized Measure of Discounted Future
Cash Flows
United
States
Canada/
South America
(1)
Europe
Africa
Asia Pacific/
Middle East
Russia/
Caspian
Total
(millions of dollars)
Consolidated subsidiaries
As of December 31, 2005
Future cash inflows from sales of oil and gas
$
200,119
$
54,953
$
107,127
$
127,584
$
44,411
$
35,757
$
569,951
Future production costs
34,100
14,460
19,958
21,856
12,515
5,324
108,213
Future development costs
8,935
3,562
8,552
12,464
2,651
4,000
40,164
Future income tax expenses
67,581
12,343
47,999
51,610
13,151
6,608
199,292
Future net cash flows
$
89,503
$
24,588
$
30,618
$
41,654
$
16,094
$
19,825
$
222,282
Effect of discounting net cash flows at 10%
53,919
10,641
9,988
15,337
6,800
12,379
109,064
Discounted future net cash flows
$
35,584
$
13,947
$
20,630
$
26,317
$
9,294
$
7,446
$
113,218
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity
companies
$
7,000
$
—
$
11,043
$
—
$
34,214
$
7,735
$
59,992
Consolidated subsidiaries
As of December 31, 2006
Future cash inflows from sales of oil and gas
$
139,843
$
61,187
$
83,854
$
117,068
$
100,751
$
42,264
$
544,967
Future production costs
39,829
20,639
19,134
22,316
36,008
3,597
141,523
Future development costs
11,134
4,023
10,245
10,429
6,098
5,307
47,236
Future income tax expenses
42,665
12,951
34,050
48,235
35,200
8,156
181,257
Future net cash flows
$
46,215
$
23,574
$
20,425
$
36,088
$
23,445
$
25,204
$
174,951
Effect of discounting net cash flows at 10%
28,428
11,429
6,464
12,069
12,777
16,932
88,099
Discounted future net cash flows
$
17,787
$
12,145
$
13,961
$
24,019
$
10,668
$
8,272
$
86,852
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity
companies
$
6,337
$
—
$
7,952
$
—
$
27,136
$
8,490
$
49,915
Consolidated subsidiaries
As of December 31, 2007
Future cash inflows from sales of oil and gas
$
216,287
$
49,985
$
115,741
$
184,358
$
158,292
$
64,351
$
789,014
Future production costs
59,154
17,422
21,356
34,721
38,098
6,537
177,288
Future development costs
13,422
5,487
10,166
21,258
5,903
7,513
63,749
Future income tax expenses
63,042
7,383
54,065
75,441
83,349
13,387
296,667
Future net cash flows
$
80,669
$
19,693
$
30,154
$
52,938
$
30,942
$
36,914
$
251,310
Effect of discounting net cash flows at 10%
51,521
7,607
9,515
20,099
14,021
25,935
128,698
Discounted future net cash flows
$
29,148
$
12,086
$
20,639
$
32,839
$
16,921
$
10,979
$
122,612
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity
companies
$
12,045
$
—
$
11,041
$
—
$
53,067
$
15,791
$
91,944
(1)
Includes discounted future net cash flows attributable to Imperial Oil Limited of $3,723 million in 2005, $5,505 million in 2006 and $6,304 million in 2007, in which there is a
30.4 percent minority interest.
Purchases/sales with the same counterparty included above
—
—
—
(699
)
(687
)
Worldwide
7,099
7,247
7,519
7,511
7,270
Gasoline, naphthas
2,850
2,866
2,957
3,301
3,238
Heating oils, kerosene, diesel oils
2,094
2,191
2,230
2,517
2,432
Aviation fuels
641
651
676
698
662
Heavy fuels
715
682
689
659
638
Specialty petroleum products
799
857
967
1,035
987
Purchases/sales with the same counterparty included above
—
—
—
(699
)
(687
)
Worldwide
7,099
7,247
7,519
7,511
7,270
(thousands of metric tons)
Chemical prime product sales
United States
10,855
10,703
10,369
11,521
10,740
Non-U.S.
16,625
16,647
16,408
16,267
15,827
Worldwide
27,480
27,350
26,777
27,788
26,567
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)
2007, 2006 and 2005 petroleum product sales data reported net of purchases/sales contracts with the same counterparty.
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