ExxonMobil (NYSE: XOM) is the largest of the vertically integrated oil majors, as well as the second largest publicly-traded corporation in the world by market cap and revenue. In 2010 the company's total earnings were $30.5 billion (excluding special items), up 57% from 2009.
ExxonMobil leads a pack of six global "supermajor" petroleum companies which explore for, produce, refine, and market oil and gas. Of these six (including BP (BP), ChevronTexaco (CVX), Total (TOT), ConocoPhillips (COP), and Royal Dutch Shell), ExxonMobil has consistently produced the highest revenue, income, and returns on capital employed (16.3% in 2009). To diversify its revenues the company continues to expand in natural gas production through acquisitions, primarily in shale deposits, in oil sands and a wide ranging geographical presence.
Despite these strengths, ExxonMobil remains at the mercy of market maker OPEC, an organization of petroleum-producing nations that controls global oil prices by holding about 40% of the world's crude oil supply. Additionally, environmental concerns over natural gas and oil production and outside factors that come with such a geographic presence create pressure on the company. And while oil & gas hold a monopoly over the world's supply of energy, alternative energies such as biofuels pose a long-term threat to the industry.
For the full year of 2010 ExxonMobil reported $30.5 billion in earnings (excluding special items), a dramatic increase of 57% from full year 2009 results. The strong year was driven by higher crude oil and natural gas realizations, stronger refining margins and record performance in its chemical division. Additionally, the company reported $32.2 billion in capital and exploration expenditures and distributed over $19 billion to shareholders through dividends and share buyback programs. By the end of the year the company's proved reserves base was 24.8 billion oil-equivalent barrels, of which 2.8 billion came from its acqauisition of XTO Energy (XTO).
In an effort to explore new opportunities ExxonMobil has begun to place more and more investments in natural gas. In 2009 the company completed a $30 billion project to develop the world's largest natural gas field, deemed the North Field. The field is located in the Persian Gulf state of Qatar. It is expected to boost the company's gas production 12% to 9.9 billion cubic feet per day, making ExxonMobil the world's largest natural gas producer. It will also boost total oil and gas output to an equivalent of 4.3 million barrels a day. The North Field is expected to contain 900 trillion feet of natural gas.
To further expand its portfolio in natural gas, in September of 2009 ExxonMobil agreed to a joint venture with Royal Dutch Shell and Chevron to construct a liquefied natural gas facility on Barrow Island off the coast of Australia. Chevron will own 50% of the facility while Shell and Exxon will each have 25%. The facility will almost double Australia's liquefied natural gas output with an annual capacity of 15 million tonnes per year.
Shell has already signed a 20 year deal with PetroChina to buy two million tonnes per year of LNG directly from the facility. While Chevron already has interest in the facility from suppliers in Japan and Korea. It has already agreed to supply 3 million tons per year of LNG to Osaka Gas, Tokyo Gas and GS Caltex from Korea. Additionally Chevron has finalized a 15 year deal with Kora Gas to provide 1.5 million tons per year.
With the deposits of natural gas ExxonMobil expects to keep consumer demand steady through plentiful supply and low prices. It will also leverage the ability to restrict supply to increase prices or rely on the additional revenue from propane and butane deposits if needed.
In 2010 Exxon acquired XTO Energy through an all-stock transaction valuing XTO at $41 billion. It was the largest U.S. petroleum takeover since 2006 and highlighted Exxon’s continual move into shale based oil and natural gas. XTO has a strong hold in shale plays in America, including the Marcellus, the Haynesville and the Bakken basins. XTO Energy’s unconventional resource base consisted of 45 trillion cubic feet of gas.
XTO was among the companies that have driven a surge in U.S. fuel output by exploiting so-called shale plays, where rock formations are fractured with water and sand to make gas flow. This may begin a wave of acquisition as major producers look to exploit resources from shale formations. Other players such as Anadarko Petroleum Corp., Ultra Petroleum and Chesapeake Energy Corp. are among companies that have demonstrated the ability to exploit shale and may be prime candidates for acquisition. 
The acquisition complimented Exxon’s presence in other shale areas such as the Piceance Basin in Colorado. The company has been producing natural gas from the basin for more than 50 years, the Piceance Basin has an estimated 1.525 trillion barrels of in-place oil shale resources.
On April 20, 2010, an explosion and fire aboard Transocean's Deepwater Horizon drilling rig off the coast of Louisiana ruptured an oil well, causing the worst oil spill in U.S. history. The rig was operated by BP (BP). In light of this, the U.S. government conducted an environmental and economic analysis of the offshore drilling industry in the Gulf of Mexico. President Barack Obama ordered a six-month moratorium on drilling in waters 500 feet and deeper while a government commission investigated the disaster. The six-month moratorium on exploratory offshore drilling closed 33 deep water drilling platforms and the Louisiana Economic Development department estimated that 3,000 to 6,000 jobs could be lost in the first three weeks and over 10,000 within the six months.
Then in October 2010, the Obama administration lifted its moratorium on deepwater oil and gas drilling in the Gulf of Mexico. Although the costs to oil drillers were less than many predicted, oil drillers have the potential of facing higher levels of regulation concerning deepwater drilling in the Gulf.
In an effort to respond to criticism from members of Congress and to reassure the public after the Deepwater Horizon rig disaster, some of the oil majors came together to prepare for deepwater oil spills. In July 2010 Exxon Mobil (XOM), Chevron Corporation (CVX), CONOCOPHILLIPS (COP) and Royal Dutch Shell (RDS'A) agreed to pool $1 billion to establish a new company, which would be tasked to respond to offshore oil spills at up to 10,000 feet underwater. Apache Deepwater LLC, a subsidiary of Apache (APA), subsequently joined on March 16, 2011. The company would deploy equipment that could arrive within days and be operational in weeks of a spill.
The company would be a nonprofit organization called the Marine Well Containment Company and would operate the response system that would be used for any spills. The response system would use underwater equipment designed to seal busted wells and have the ability to separate oil from gas and bring it to the surface where the gas would be burned off and oil would be stored in containers. The equipment should be useful in depths up to 10,000 feet. Currently, the system has capacity to contain up to 60,000 barrels per day of fluid in up to 8,000 feet of water, with plans to expand to 100,000 barrels per day in up to 10,000 feet by 2012.
The establishment of the company was an effort for the oil majors to demonstrate that plans are in place to minimize any potential damage of deepwater drilling. All four companies rely significantly on offshore drilling, while Shell and Chevron have significant operations in the Gulf of Mexico. All companies will participate, however ExxonMobil will lead the effort. IT is an example of how it will be more expensive to drill in the Gulf of Mexico with such elaborate containment plans.
While Exxon continues to grow its presence in shale, the U.S. congress is currently examining the possibility of banning "fracing". The method is widely used to collect natural gas, especially from the Marcellus Shale which is estimated to contain 500 trillion cubic feet of natural gas. The method has come under fire, because it is thought that the chemicals and fluids used to fracture the shale contaminate nearby water supplies. This contamination has led congress to investigate a ban on the method .
This is a key method through which natural gas companies are collecting gas and oil from shale reserves. The impact of regulations against the method was highlighted by the fact that Exxon-Mobil's takeover of XTO, would have been terminated if congress were to prohibit or make "fracing" commercially unviable.
Since 2003, under a voluntary agreement with EPA, companies have not used diesel fuel as a carrier fluid during fracing, however companies have been found to possibly be in violation of this agreement. During 2005-07 Halliburton reported using more than 870,000 gal of seven diesel-based fluids, while BJ Services Company stated it used 2,500 gal of diesel-based fluids in several frac jobs. The two companies also indicated that they used chemicals such as benzene, toluene, ethylbenzene, and xylene, which could pose environmental risks in their fracing fluids. These companies and others have come under close scrutiny over possible violations of the 2003 agreement and how they are currently disposing of chemicals used during extractions. On February 18, 2010 the Energy and Environment Subcommittee Chairman Edward J. Markey sent letters to eight oil field service companies requesting information about chemicals used in hydraulic fracturing fluids.
Working in shale increasingly involves working with the U.S. government. Over 70% of American oil shale is on federal land, primarily in Colorado, Utah and Wyoming. The National Environmental Policy Act (NEPA) requires that exploration and production on federal lands be thoroughly analyzed for environmental impacts and is tightly regulated by federal or state organizations. In October 2009 the Department of the Interior stated it would offer additional opportunities for energy companies to conduct oil shale research, development and demonstration (RD&D) projects on public lands. This signals that the government understands the value of shale deposits, but also that they must be handled carefully. The results of continued research on shale projects and the success of current methods to safely extract hydrocarbons will have a dramatic effect on Exxon’s investments in these areas.
ExxonMobil’s E&P revenues depend on how much oil it produces, and for how much it can sell it. At the same time, ExxonMobil’s refining and chemicals improve their bottom-line when the price of their greatest input, oil, goes down. As a whole, ExxonMobil benefits when oil prices increase, as it makes more from E&P than it does from refining and chemicals, and a drop off in oil prices is often caused by a slowdown in economic growth, which causes demand destruction for all of its products. Factors affecting demand include:
Factors effecting supply include:
Demand for oil, as well as demand for energy in general, is closely tied to the global economic cycle. In periods of economic growth, new factories consume energy, shipping companies transport more goods and consumers take more trips. Burgeoning underdeveloped economies like China are expected to make the Asia Pacific natural gas market grow faster than any other regional gas market in the world. China's demand for oil is lower than other countries' at 2 barrels per person per year (bpy)—America’s is 25 bpy and Japan’s 16 bpy.
The long-term trend is clear – energy consumption is going to increase. However, these projections were made in June of 2008; a slight downward revision is likely in the next release in May of 2009.
Demand for oil, as well as demand for energy in general, is closely tied to the global economic cycle. During periods of economic contraction such as recessions, demand for oil and other types of energy tends to fall, leading to reductions in price. Demand destruction - primarily in the United States - is likely responsible for most of the drop in oil prices that occurred during the third quarter of 2008.
In 2008 world oil consumption of liquid fuels was 85.75 million barrels per day (bbl/d), 3% less than forecasts made by the International Energy Agency at the end of 07. World oil consumption was forecasted in April of 2009 by the EIA to fall 1.35 million bbl/d in 2009.
Much of this demand destruction is likely rooted in the 2007 Credit Crunch, the 2008 Financial Crisis, and the resulting recession; when unemployment rises, people stop spending and start saving. When people stop spending, companies stop producing. When companies stop producing, demand for energy falls. When demand for energy falls, the price of oil falls. Hence, it is likely that oil prices will remain lower than before until the world economy recovers from its recession.
The global oil supply is dependent on the ability of oil companies to produce and the willingness of oil-exporting countries to export. Historically, periods of oil price spikes have been caused by oil-exporting countries placing embargoes on certain countries. In 1973, for example, the world's largest oil cartel, OPEC, placed an embargo on oil exports to the Netherlands and the United States, in response to the countries' support of Israel in the Yom Kippur War; the price of oil acquired by refiners increased by approximately 100%, and the U.S. experienced widespread shortages. In 2007, however, despite a 57% increase in prices, the amount of oil exported by the world's top exporters fell 2.5%. Demand for oil in the world's six largest exporters (Saudi Arabia, United Arab Emirates, Iran, Kuwait, Iraq and Qatar) increased by more than 300,000 barrels, while their exports fell by over half a million barrels. In this case, growing demand in each company acted as a natural embargo, forcing them to meet their own needs before exporting to the rest of the world.
The Financial Crisis of 2008 laid waste to oil prices, by causing a recession so deep even expectations of large supply cuts couldn't force prices up. In December 2008, OPEC announced a production cut of 2.2 million barrels - it's largest ever - and oil futures actually fell, as traders ignored decreasing supply and focused on decreasing demand.
Peak oil refers to the "peak" on the graph of global oil production. Oil must first be discovered, then produced, and will eventually be depleted. Oil production has already peaked in the USA and more than 50 other oil producing countries. Once the halfway point "peak" has been passed, production begins to fall and oil prices will rise. This is not good for Exxon. Although oil prices will rise, production costs will also rise, as traditional oil producing basins dry and reliance on expensive deepwater reserves increases. Production will also likely fall for Exxon, just like with any other oil company. Worse, as demand further outstrips supply and oil prices skyrocket, alternative energies will become increasingly competitive.
ExxonMobil’s bottom line depends on how much it costs to produce the oil that it eventually refines and/or sells. About 30% of its oil came from expensive, nonconventional reserves in 2008. As its traditional oil-basins mature, that percent is expected by the company to rise to 40% by 2013.
Nonconventional reserves include arctic and deepwater reserves, heavy oil, tight gas, and liquefied natural gas. Even in the low price environment of 2008 and 2009, producing from nonconventional reserves makes sense for ExxonMobil, as does increasing its CapEx. For new projects it can take up to 10 years for actual production to begin, meaning that the future price of oil determines profitability, not the current price. Also, ExxonMobil is locked into many long-term contracts with rig operators, under which terms it costs almost as much to idle as it does to produce.  However, if ExxonMobil spends billions on setting up new production and oil prices do not rise as expected, the company’s margins will shrink.
One-third to half of the world’s petroleum reserves may rest in the form of oil sands. ExxonMobil’s leases in the Kearl oil sands, located in Alberta, Canada, have proven reserves of 1,137 million barrels, and represents a significant portion of the company’s total oil reserves, but will, with the development of better extraction and refining technology, double or triple into reserves of two to four billion barrels. The leases are part of a joint venture with Imperial Oil Limited. Imperial holds 71% of the interest and ExxonMobil Canad Properties holds the other 29%. Notably, ExxonMobil Corporation holds a 70% interest in Imperial Oil and 100 percent of ExxonMobil Properties. In addition to a strong position in the Kearl oil sands, the majority ownership enables Exxon to leverage the fact that Imperial has 140 years worth of proven oil and natural gas preserves without additional drilling.
However, oil from sand deposits is very thick, and must be highly processed before it can flow and be distributed for use. These nonconventional reserves cost, on average, $35/barrel to pump and convert into synthetic fuel, as compared to $3 a barrel in Saudi Arabia and release three times as much CO2 as during conventional production. That means that the implementation of a carbon tax or carbon trading scheme would make oil sands production even more expensive. More troubling for the company, the cost of new production can exceed $75 a barrel, as production in easy to reach places has already been set up. At the same time, ExxonMobil has taken a long-term perspective on its CapEx. It expects oil prices to be higher in 2012, by which time production from its expanded program will begin. 
While ExxonMobil is less at risk than some of its US competitors from restrictive legislation because ExxonMobil is not focused only in the US, this global presence brings problems from foreign politics and exchange rate risk as well. About 60% of the world’s supply of oil comes from geopolitically unstable countries including Saudi Arabia and Venezuela. High oil prices in 2007 and 2008 gave these oil exporting countries greater power to demand contract changes and tax raises, and greater incentives to nationalization private oil holdings, like Venezuela did of Exxon's holdings in 2007. In 2009, with oil prices back to historical levels, many countries are providing more favorable contracts in hopes of attracting much needed development money.
Fossil fuels, though highly cost-efficient forms of energy, are heavy polluters when burned. Increasing environmental concern over environmental degradation and global climate change is fueling a consumer-driven push away from dirty forms of energy toward cleaner forms like wind energy and solar power. These concerns are also causing political movements, which are leading to increased regulation in the fossil fuels market. Government regulations like emissions caps, renewable energy subsidies, and carbon trading schemes all facilitate transitions away from dirty, nonrenewable fuels.
An increasingly popular response to global warming is carbon trading. Markets have been implement in the EU and through the Kyoto Protocol, and may soon find a home in the U.S. How much do they cost Exxon? The average barrel of oil that passes through U.S. refineries produces about 100kg of CO2 emissions. The cost of permits for polluting one ton of CO2 in Europe has ranged from €30/tonne to €0.03/tonne. That translates into only $.004/barrel to $4/barrel. In a properly functioning carbon trading market (or tax equivalent) it’s estimated that the cost/tonne should hover around $20-$40 dollars, which is $2/barrel - $4/barrel. Only a portion of that cost was and will be borne by Exxon, although the resulting higher price of oil does reduce demand (which translates into lower revenues). Taking the hypothetical case that Obama is able to push through Congress to create a carbon trading market in the U.S., Exxon’s largest market, the company would lose a couple billion dollars a year.
The quantity of economically recoverable oil underneath the Arctic National Wildlife Refuge (ANWR) is estimated to be at around 10 billion barrels. Concerns over the area’s wildlife has prevented competitor Shell from drilling in its ANWR blocks. Gaining control of even one-tenth of the area’s oil would boost Exxon’s oil reserves by 14%.
Exxon has traditionally focused on rising costs in the form of carbon trading or taxation, rather than in demand being stolen by renewable energy. However, in the middle of 2009 the company announced renewed investments in biofuels.
Prior investments included:
In July of 2009 Exxon announced a $600 million investment in producing biofuels from algae. The investment involves a partnership with a biotechnology company, Synthetic Genomics. $300 million will be used for in-house studies, while the additional $300 million will be allocated to Synthetic Genomics based off meeting research and development milestones.
Large scale commercial plants to produce algae-based biofuels are reported to be at least 5 to 10 years away, but have the potential to yield more than 2,000 gallons of fuel per acre of production each year. In comparison: palm trees produce 650 gallons, sugar cane 450 gallons and corn yields just 250 gallons per acre a year.
Natural disasters can significantly disrupt Exxon’s oil production operations. For instance, hurricane activity can damage and destroy refineries, oil rigs, pipelines, and other equipment. In 2005, production declined 15% and Exxon lost 33 MBOED (million barrels oil equivalent per day) of production due to the impact of Hurricanes Katrina and Rita on Gulf Coast oil production operations owned by the company. In 2008, production declines and repair expenses attributed to the damage caused by Hurricanes Gustav and Ike lowered fourth quarter earnings by $570 million.
Exxon Mobil is the biggest of the supermajors, the six largest public energy companies in the world - Royal Dutch Shell, Chevron, BP, Total S.A., and ConocoPhillips. Exxon's efficiency is attributable to several advantages over its competitors:
But unlike some of its foreign competitors, the American ExxonMobil is constrained by economic sanctions that ban it from doing business with some of the world's largest oil states, including Iran, estimated to have the second largest reserves of conventional crude oil in the world.
Another growing concern for public energy companies worldwide is the increasing competition coming from national oil companies like Saudi Aramco and NIOC of Iran.
|CONOCOPHILLIPS||ROYAL DUTCH SHELL||EXXONMOBIL||CHEVRON||BP||LUKOIL(1)||Eni S.p.A(1)||Total S.A.|
|Oil and Gas Liquids|
(Millions of barrels)
(Billions of cubic feet)
|Oil and Gas Liquids|
(1) Latest data is for 2007 (2) Does not include reserves of equity affiliates
|Number of Refineries (including partial interests)||5||18||16||37||40||17||4||12||17||9||N/A||25|
|Number of Retail Gas Stations (thousands)||7.8||25||5.8||28.6||45||29||.2||8.3||22.6||6.3||6.4 (in Europe)||16.4|
(1) Latest data is for 2007
Anadarko Petroleum BP ChevronTexaco Arch Coal Cameco ConocoPhillips Enbridge Consolidated Edison Entergy Exelon Exxon Mobil Frontier Oil GE Halliburton Philips Massey Energy Occidental Petroleum PG&E Peabody Energy Shell Sasol Schlumberger Sinopec Suncor Sunoco SunPower Suntech Suzlon Toshiba Valero Xcel