Financial & Operating Summary			1
Business Model			2
Competitive Advantages			3
Global Operations			4
Upstream			6
Downstream			52
Chemical			70
Financial Information			84
Frequently Used Terms			93
Index			96
General Information			97

2011: Financial & Operating Summary

Our competitive advantages formed the framework for solid financial and operating results across all key measures and businesses in 2011. We achieved strong earnings and generated robust returns for our shareholders. We also continued to invest in attractive projects that position the company for sustained long-term growth and profitability.

FINANCIAL HIGHLIGHTS

						Average				Return on				Capital and
		Earnings After				Capital				Average Capital				Exploration
(millions of dollars, unless noted)		Income Taxes				Employed		(1)		Employed (%)		(1)		Expenditures		(1)
Upstream			34,439				129,807				26.5				33,091
Downstream			4,459				23,388				19.1				2,120
Chemical			4,383				19,798				22.1				1,450
Corporate and Financing			(2,221	)			(2,272	)			N.A.				105
Total			41,060				170,721				24.2				36,766

OPERATING HIGHLIGHTS

Liquids production (net, thousands of barrels per day)			2,312
Natural gas production available for sale (net, millions of cubic feet per day)			13,162
Oil-equivalent production(2) (net, thousands of oil-equivalent barrels per day)			4,506
Refinery throughput (thousands of barrels per day)			5,214
Petroleum product sales (thousands of barrels per day)			6,413
Chemical prime product sales (thousands of tonnes)			25,006

OTHER RESULTS & HIGHLIGHTS

Safety performance remains strong in industry		Total shareholder return of 19 percent(1)
Strong cash flow from operations and asset sales of $66.5 billion(1)		Total shareholder distributions of $29 billion(1)
Proved oil and gas reserve additions of 2.0 billion oil-equivalent barrels, replacing 116 percent of production, excluding asset sales(1)		Annual dividend per share growth of 6 percent versus 2010, the 29th consecutive year of dividend per share increases

2		ExxonMobil • 2011 Financial & Operating Review

 

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ExxonMobil • 2011 Financial & Operating Review

ExxonMobil’s 2011 Upstream financial and operating results included strong safety and environmental performance, high facility reliability, continued operational and capital spending discipline, and solid production volume growth.

Strong safety and operations performance supported by effective risk management

Industry-leading earnings of $34.4 billion

Return on average capital employed of 26.5 percent, averaging 33.7 percent over the last five years

Earnings per oil-equivalent barrel of $20.94

Total net production of 4.5 million oil-equivalent barrels per day, an increase of 1 percent versus 2010

Proved oil and natural gas reserve additions of 2.0 billion oil-equivalent barrels, replacing 116 percent of production, excluding asset sales

Resource base additions totaling 4.1 billion oil-equivalent barrels, increasing the overall resource base to 87 billion oil-equivalent barrels

Exploration resource addition cost of $1.40 per oil-equivalent barrel

Upstream capital and exploration spending of $33.1 billion with total investment over the past five years at more than $116 billion

Made a significant oil discovery in the U.S. Gulf of Mexico with the Hadrian-5 exploration well

Signed a strategic cooperation agreement with Rosneft

UPSTREAM STATISTICAL RECAP		2011				2010				2009				2008				2007
Earnings (millions of dollars)			34,439				24,097				17,107				35,402				26,497
Liquids production (net, thousands of barrels per day)			2,312				2,422				2,387				2,405				2,616
Natural gas production available for sale (net, millions of cubic feet per day)			13,162				12,148				9,273				9,095				9,384
Oil-equivalent production(1) (net, thousands of barrels per day)			4,506				4,447				3,932				3,921				4,180
Proved reserves replacement(2)(3) (percent)			116				211				100				143				107
Resource additions(2) (millions of oil-equivalent barrels)			4,086				14,580				2,860				2,230				2,010
Average capital employed(2) (millions of dollars)			129,807				103,287				73,201				66,064				63,565
Return on average capital employed(2) (percent)			26.5				23.3				23.4				53.6				41.7
Capital and exploration expenditures(2) (millions of dollars)			33,091				27,319				20,704				19,734				15,724

(1)		Natural gas converted to oil-equivalent at 6 million cubic feet per 1 thousand barrels.
(2)		See Frequently Used Terms on pages 93 through 95.
(3)		Proved reserves exclude asset sales and the 2007 Venezuela expropriation. Includes non-consolidated interests and Canadian oil sands.
Note: Unless otherwise stated, production rates, project capacities, and acreage values referred to on pages 8 through 41 are gross.

Our Upstream business includes exploration, development, production, natural gas and power marketing, and research activities. ExxonMobil pursues a balanced global exploration program designed to test new high-potential exploration areas, explore emerging unconventional opportunities, and add resources through ongoing activity in established areas. We have an industry-leading resource base and a diverse portfolio of projects that span a broad range of environments, resource types, and geographies. We continue to grow our resource base through successful by-the-bit drilling, capture of undeveloped resources, strategic acquisitions, and increased recovery from existing fields. Our approach to investing is to advance opportunities that are likely to provide competitive returns across a broad range of potential market conditions. We have nine projects expected to come online during 2012 and 2013, including three in Nigeria, one in Australia, one in Canada, one in Angola, and one in Malaysia. During this time frame, we also expect to start up the Kearl Initial Development project in Canada and the first phase of the Kashagan development in Kazakhstan. These projects will provide us with a strong foundation for future production growth and add to our existing world-class global portfolio of producing assets.

Oil and natural gas are expected to continue to play a leading role in meeting the world’s growing demand for energy. In fact, by 2040, oil and natural gas are projected to be the world’s top two energy sources, accounting for about 60 percent of global demand, versus about 55 percent today.

Demand for oil and other liquid fuels is forecast to increase by almost 30 percent over the next 30 years. As conventional oil production holds relatively flat through 2040, demand growth is expected to be met by new sources. The largest volume gain is likely to come from global deepwater production, which is estimated to more than double through 2040. We also project significant growth in production from oil sands, tight oil, and natural gas liquids. As a result of the growth in these newer resources, we anticipate that conventional oil will account for only about 60 percent of liquid fuels supply by 2040, down from 80 percent in 2010.

Natural gas is expected to be the fastest-growing major fuel through 2040, with demand increasing by more than 60 percent. A rising share of global natural gas demand will likely be met by unconventional gas supplies, such as those produced from shale and other rock formations.

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Balanced Portfolio

ExxonMobil’s Upstream portfolio includes high-quality exploration opportunities, an industry-leading resource base, a broad range of world-class development projects, and a set of diverse producing assets.

Our fundamental exploration strategy is to identify, evaluate, pursue, and capture the highest-quality opportunities across all resource types and in any environment. The combination of technical expertise, extensive global databases, and industry-leading research facilities provides us with a distinct competitive advantage in the pursuit, capture, and commercialization of new resources. In fact, recognition of these capabilities creates opportunities for us as other organizations seek a partner with our broad skills and experience.

We screen prospects for quality, materiality, and commercial viability. Technical capabilities and knowledge of the global hydrocarbon endowment allow us to identify and evaluate quality resources in the highest-potential basins. Careful consideration is given to ensure diversity and balance in our exploration portfolio with respect to resource type and risk. Only the best opportunities are selected for further investment. Once an opportunity is captured, we evaluate it in the most cost-effective manner and then apply what we learn to future investment decisions. This approach has led to the successful capture of new, high-potential resource opportunities every year.

We significantly expanded our prospective exploration portfolio in 2011 with the successful capture of 24 new opportunities in seven countries. At year-end 2011, net exploration acreage totaled 61 million acres in 32 countries. This strong position provides us with a high-quality, geographically and geologically diverse portfolio of prospects that underpins future resource additions and production growth. We participated in exploration drilling in 2011 involving conventional opportunities in established basins such as the Gulf of Mexico, frontier basins in the Black Sea, liquefied natural gas (LNG) opportunities in Australia, and unconventional oil and gas assets in the United States and Canada. We added approximately 4.1 billion oil-equivalent barrels to our resource base as a result of these successful efforts to identify, capture, and test new opportunities.

Our global portfolio of high-quality development projects and producing assets reflects a diverse range of resource types and operating environments. These projects and producing assets also span a broad range of maturities including new greenfield developments such as Kearl, Papua New Guinea (PNG) LNG, and Gorgon Jansz; early production assets like Odoptu in Sakhalin; and long-life assets such as Qatar, Tengiz, and Cold Lake.

 

In 2011, we continued to build on our already strong and diverse resource position with the capture of 24 new opportunities. These opportunities included both unconventional and conventional play types. As part of this successful effort, we leveraged experience gained in unconventional plays in North America to capture new acreage positions in both Argentina and Indonesia.

Argentina • ExxonMobil acquired an additional 636,000 net acres in the potentially liquids-rich portion of the Neuquen Basin in Argentina through strategic joint ventures. Two wells to evaluate the potential of this acreage commenced drilling in late 2011.

Canada • We expanded our position in the unconventional plays of the Western Canada Basin by adding 499,000 net acres through various provincial lease sales during the year. Exploration drilling also continued to test these highly-prospective plays.

Faroe Islands • In March 2011, ExxonMobil acquired a 49-percent interest in license L006 and a 50-percent interest in licenses L009 and L011 in the Faroe Islands, covering 1.1 million acres. The Statoil-operated Brugdan-2 wildcat is scheduled to be drilled on license L006 in 2012.

Indonesia • Early in 2011, we joined a production sharing contract to explore 700,000 net acres in Kalimantan to evaluate coal bed methane potential.

Iraq • In October 2011, ExxonMobil signed production sharing contracts for six blocks covering 848,000 acres in the Kurdistan Region of Iraq.

Norway • In May 2011, we acquired a 35-percent operating interest in the PL596 Møre Vest license, covering 787,000 acres, and a 30-percent interest in the PL598 Ygg High license, covering 409,000 acres.

U.S. Onshore • During the year, we increased by 80 percent our position in the Marcellus Shale gas play in the United States by acquiring approximately 310,000 net acres. Acquisitions also included roughly 45,000 net acres in the emerging, liquids-rich Utica Shale play in eastern Ohio, bringing our total position in that play to roughly 75,000 net acres at year-end 2011. In addition, through leasing and multiple acquisitions, we captured an industry-leading position of 172,000 net acres in the liquids-rich Woodford Ardmore Shale play of southern Oklahoma. ExxonMobil also added more than 154,000 net acres in the prospective tight oil plays of the Permian Basin in West Texas.

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Resources

ExxonMobil has a diverse, global portfolio of resources and reserves. We expanded our industry-leading resource base in 2011 by adding 4.1 billion oil-equivalent barrels. After adjusting for production, asset sales, and revisions to existing fields, the

resource base now totals more than 87 billion oil-equivalent barrels. Proved reserves comprise approximately 29 percent of the resource base, or 24.9 billion oil-equivalent barrels.

The success of our global strategy to identify, evaluate, pursue, and capture opportunities is demonstrated by the addition of an average of 5.2 billion oil-equivalent barrels to our resource base per year over the past five years. ExxonMobil’s resource base is the largest among international oil companies, resulting in a significant competitive advantage. The size and diversity also support risk management and investment flexibility.

We continue to grow the resource base through successful by-the-bit drilling, capture of undeveloped resources, strategic acquisitions, and increased recovery from existing fields. We added resources in 2011 from the deepwater
Gulf of Mexico, Australia, Indonesia, Vietnam, the Athabasca and Horn River plays in Canada, and onshore fields in the United States.

Our resource base is updated annually for new discoveries and changes in estimates for existing resources. These changes may result from additional drilling, revisions to recovery estimates, or the application of new technology. Updates may occur due to changes in fiscal regime, equity, or depletion plans. They also come from ongoing and rigorous geoscience and engineering technical evaluations. The volumes we produce during the year and the resources associated with asset divestments are also removed from the resource base at year end.

The largest component of ExxonMobil’s resource base remains conventional oil and gas and deepwater, which comprises 29 percent of the total. Heavy oil, predominantly located in Canada, accounts for just over 21 percent. Over the last decade, our position in both liquefied natural gas and unconventional gas and oil has increased significantly and makes up about 31 percent of total resources. The remainder is made up of arctic and acid/sour gas resources.

Application of proprietary processes and best practices has resulted in consistently low exploration resource addition costs. For example, in 2011, our exploration resource addition cost was $1.40 per oil-equivalent barrel, with the five-year average cost at $1.15 per oil-equivalent barrel. The 2011 resource additions provide us with an attractive set of future development opportunities.

ExxonMobil’s resource base includes 24.9 billion oil-equivalent barrels of proved oil and gas reserves, equating to 15 years of reserves life at current production rates. These reserves represent a diverse global portfolio distributed across all geographic regions and resource types, with an almost equal split between oil and natural gas.

We replaced 107 percent of the reserves we produced in 2011, including the impact of asset sales. We added 1.8 billion oil-equivalent barrels to proved reserves while producing 1.7 billion oil-equivalent barrels. Excluding asset sales, our proved reserves replacement ratio was 116 percent. Key proved reserve additions came from the Kearl Expansion project, which was sanctioned in 2011, and from unconventional assets in North America.

ExxonMobil has added 10 billion oil-equivalent barrels to proved reserves over the last five years, more than replacing production in that time frame. The development of new fields and extensions of existing fields have resulted in the addition of an average of 1 billion oil-equivalent barrels per year to proved reserves. Revisions to proved reserves have averaged about 0.7 billion oil-equivalent barrels per year over the last five years, driven by effective reservoir management and the application of new technology. We have more than replaced our production for 18 consecutive years. Proved reserve estimates are managed by a team of experienced reserve experts, and are the result of a rigorous and structured management review process.

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Disciplined Investing

A disciplined approach to investing combines effective project assessment and development with technical and commercial expertise. We apply this approach to initial resource capture, project execution, and ongoing operations to achieve superior returns on investment.

Investment decisions in the energy industry are characterized by a time horizon measured in decades. As such, our projects are tested over a wide range of economic scenarios to ensure risks are properly identified, evaluated, and managed. ExxonMobil’s approach to investing in this cyclical business is to advance opportunities that will provide the most attractive returns across a broad range of potential market conditions, while maintaining a focus on the efficient use of capital. Proven project management systems incorporate best practices and are applied consistently around the world. Utilizing a disciplined gate review process, experienced global project teams rigorously manage our project portfolio from initial discovery to start-up.

We have a large, geographically diverse portfolio of more than 120 projects targeting development of 23 billion oil-equivalent barrels. These projects span a wide range of environments, resource types, and geographies, and provide us with the ability to selectively invest in those projects that are likely to deliver robust financial performance and profitable volumes growth.

Portfolio management is also a key aspect of disciplined investing. In 2010 and 2011, we completed sales involving interests in the Beryl field in the North Sea, the Gassled Transportation System in Norway, a gas storage business in Germany, conventional gas properties in western Canada, XTO’s legacy Gulf of Mexico properties, more than 50 shallow-water platforms in the Gulf of Mexico, and the Tempa Rossa joint venture in Italy.

Pazflor • (ExxonMobil interest, 20 percent) Pazflor started up in August 2011 utilizing a floating production, storage, and offloading (FPSO) vessel located approximately 100 miles offshore Angola in Block 17. The facility is expected to produce approximately 220 thousand barrels of oil per day through three subsea separation units.

Kizomba Satellites Phase 1 • (ExxonMobil interest, 40 percent) Kizomba Satellites Phase 1 is scheduled to start up in the third quarter 2012 as a subsea tie back to the existing FPSO facilities in Angola Block 15. The project is expected to drill 18 wells and recover nearly 250 million barrels of oil, with a peak production rate of 100 thousand barrels of oil per day.

Kearl Initial Development • Kearl Initial Development (combined ExxonMobil and Imperial Oil interest, 100 percent) is expected to start up by year-end 2012. The Initial Development is anticipated to produce 110 thousand barrels of bitumen per day, with future potential of up to 170 thousand barrels of bitumen per day after debottlenecking. Kearl represents the first mining operation to employ a new proprietary paraffinic froth treatment technology, which produces a salable crude oil without an upgrader. As a result, Kearl’s life cycle greenhouse gas emissions will be no greater than that of the average crude oil consumed in the United States.

 

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High-Impact Technologies

ExxonMobil’s commitment to invest in technology enables us to develop innovative solutions to improve safety, minimize environmental impact, reduce costs, increase reliability, and maximize resource value. Integrated technologies have unlocked value from previously uneconomic resources, including heavy oil and those trapped in tight reservoirs, as well as in difficult environments such as the Arctic and deep water.

salt and is critical for planning safe and economic drilling programs. These predictions help us to identify optimum drilling trajectories, reduce drilling-related wellbore instabilities, and decrease the likelihood of sidetrack drilling.

This approach requires high-performance computing to enable the development of 3D full-field model solutions on a schedule compatible with well planning. We are applying this emerging geomechanical modeling technology to salt provinces in the Caspian Sea, Angola, and the Gulf of Mexico. Recent applications of this technology resulted in the elimination of hole-related, nonproductive rig time in wells located near salt. This compares with five to eight days of nonproductive rig time for previously drilled wells nearby.

One of the key technologies enabled by ExxonMobil’s petascale high-performance computing facility is our industry-leading seismic imaging capability.

Our researchers are developing seismic imaging technology that will generate high-definition subsurface models of geologic structures and rock properties. Proprietary computer algorithms accelerate massive computational tasks allowing our geophysicists to incorporate the full physics response, which is well beyond what is possible by conventional methods today. One such advance is the ability to simulate the full complexity of seismic wave propagation in the earth. ExxonMobil’s proprietary inversion methodology, which uses iterative inversion of data from simultaneous sources, is the basis for our EMPrise technology. This recently patented seismic imaging technology positions us to be the industry leader in full wavefield inversion.

Full wavefield inversion will provide our geoscientists with focused 3D models of subsurface rock properties, predicted from seismic data, well in advance of drilling activities. At the initiation of this research program, we estimated that a single project would take tens of thousands of years to compute using the fastest computing technology then

available. Capitalizing on advances in computing, and with proprietary technologies, we expect to produce high-fidelity subsurface images that are unmatched in industry, and in a time frame that is practical for business application.

We have an impressive record of completing successful developments in challenging environments, with over 90 years of experience in the Arctic, and a suite of patented technologies that position us as the industry leader in extended-reach drilling (ERD). We have drilled 23 of the world’s 27 longest-reach wells. These long-reach wells enable development of oil and gas with a reduced footprint and less environmental impact.

We continue to advance ERD by progressing several additional drilling and completion technologies. ExxonMobil’s patented Internal Shunt Alternate Path Technology (ISAPT) saw its first commercial application with zonal isolation in 2011. ISAPT enables reliable long horizontal well completions in

unconsolidated sandstone formations. Our cuttings transport approach is supported by large-scale experiments and advanced physics-based modeling. In addition, ExxonMobil’s patented VYBS technology reduces drill string vibration.

We are developing technologies to reduce both the environmental impact and the cost of extracting bitumen, a heavy oil resource that is either mined or developed in situ.

New stratigraphic and geologic modeling technologies allow for more accurate predictions of the oil sands resources in place, reducing the number of core holes drilled for development. New land and shallow seismic methods are also providing low-cost geophysical data for resource characterization.

As a founding member of the Oil Sands Tailings Consortium (OSTC), Imperial Oil, an ExxonMobil affiliate, is working to accelerate industry-wide solutions to one of the largest environmental challenges for heavy oil assets. This unique partnership opens the door for collaboration in the development of next-generation reclamation technologies. We are leveraging the OSTC to evaluate new tailings treatment technologies prior to start-up of our Kearl oil sands project in late 2012. Additionally, we are progressing the development of proprietary technology to allow for nonaqueous extraction of bitumen, which has the potential to significantly reduce water usage and ultimately eliminate the need for wet-tailings ponds.

ExxonMobil and Imperial Oil are also advancing bitumen recovery technologies to facilitate commercial development of additional in situ bitumen resources, which are buried too deep for mining, while improving environmental performance. Current efforts are focused on the use of solvents to access undeveloped resources, improve bitumen recovery, and reduce greenhouse gas emissions. The patented Liquid Assisted Steam Enhanced Recovery (LASER) technology, first commercially applied at Cold Lake, increases bitumen recovery rates by adding a small amount of solvent to an existing high-pressure cyclic steam injection technology application. Additionally, we are progressing a Cyclic Solvent Process field pilot, which is scheduled for a 2013 start-up. Results from pre-commercial trials and pilots of these technologies will provide invaluable information, allowing us to optimize our long-term resource development plan and increase bitumen production.

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Operational Excellence

We rigorously apply management systems worldwide to enable consistent application of the highest operational standards. We maximize the value of existing assets through strong reliability performance and selective investment.

Operational integrity is an essential aspect of our ongoing success. ExxonMobil’s Operations Integrity Management System (OIMS) encompasses all aspects of our operations and enables us to understand and minimize risks. OIMS is used consistently around the world with compliance tested on a regular basis.

In addition to OIMS, ExxonMobil employs a comprehensive set of risk management systems to address the risks found in all aspects of our operations. For example, we have risk management systems to monitor drilling, construction and project management, facility integrity, and well work. We also manage the risks associated with supporting activities such as aviation and logistics, business controls, and the oversight of joint-venture assets.

ExxonMobil achieves high facility uptime by leveraging a suite of equipment maintenance best practices that we have developed over our considerable operational history. Large-scale maintenance activities are rigorously planned and executed using a globally consistent shutdown management process to minimize production impact.

We focus on the effective management of base performance through rigorous operational surveillance and optimization. Through effective reservoir management and depletion planning, we increase economic resource recovery, maximize profitability, and ensure optimum long-term field performance. New production volumes are added through drill wells, workovers of existing wells, and secondary and tertiary recovery programs. These programs increase resource recovery using water, gas, or carbon dioxide, heavy oil steam flooding, and sour gas injection techniques. We continue to selectively progress an inventory of investment opportunities to derive the most value from existing assets. ExxonMobil also seeks to maximize efficiencies and cost savings in drilling operations with the application of our proprietary Fast Drill process and extended-reach drilling capabilities.

We develop and deploy management systems across the various aspects of our business to maximize the efficiency and value of our assets.

ExxonMobil’s approach to operational excellence allows us to deliver consistent volumes growth and maximize the profitability of existing oil and gas production. Net oil-equivalent production in 2011 of 4.5 million barrels per day increased by 1 percent over 2010 levels. Excluding the impacts associated with entitlement volume effects, quotas, and divestments, our net oil-equivalent production increased by more than 4 percent versus 2010, primarily driven by unconventional activities in the United States and project activity in Qatar, Angola, Russia, and Iraq, which more than offset field decline.

Near-term volume growth will focus on large liquids projects in Iraq and Canada, liquefied natural gas projects in Papua New Guinea and Australia, and unconventional gas and liquids activity in the United States. Longer-term growth will leverage our technical expertise in developing a diverse global project portfolio. We are already pursuing a number of these projects, many of which will result in long-plateau production profiles that run for decades.

The forward-looking projections of production volumes in this document are reflective of our best assumptions regarding technical, commercial, and regulatory aspects of existing operations and new projects. Factors that could impact actual volumes include project start-up timing, regulatory changes, quotas, changes in market conditions, asset sales, operational outages, severe weather, and entitlement volume effects under certain production sharing contracts and royalty agreements.

 

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Global Integration

The benefit we derive from a globally integrated business model is one of the primary reasons we are able to successfully develop some of the most challenging energy projects. Global functional organizations, robust management processes, and best practices combined with an ability to leverage expertise across ExxonMobil’s Upstream, Downstream, and Chemical businesses enable us to identify and deliver innovative solutions for our operations and projects.

GLOBAL FUNCTIONAL ORGANIZATION

Our global functional organization allows us to leverage expertise and knowledge in every location where we conduct business. In doing so, we combine the strengths of local affiliates and centralized locations to maximize the value of our global portfolio. Utilizing global engineering organizations, we deploy technical expertise to develop optimal solutions to the operational challenges we face around the world. For example, Maximizing Recovery Workshops are designed to identify opportunities to profitably capture additional hydrocarbons in existing assets. Over the past four years, we have conducted these workshops on many of the major fields operated by ExxonMobil, which has led to resource additions of approximately 1.8 billion oil-equivalent barrels. As a result, we defined and

deploying a global Work Management System. This system helps to ensure work activities at operating sites are planned and executed in a structured and controlled manner, allowing us to effectively manage risks and safety exposures. We developed the Work Management System by utilizing an electronic work permit process, and by leveraging operational experience from around the globe. We anticipate the system will deliver additional work execution efficiencies and improvements in safety performance.

In addition, ExxonMobil employs a worldwide team of commercial experts, armed with detailed knowledge of global energy markets, to maximize the value of our natural gas and natural gas liquids production.

INTEGRATION ACROSS THE VALUE CHAIN

Integrated commercial activities across the resource value chain support development of our Upstream projects. For example, the mega-train ventures in Qatar demonstrated the importance of economies of scale and the competitive advantages obtained through the integrated development of large gas resources. The integration of field development, liquefaction, shipping, and regasification in key global markets resulted in significant benefits for the Qatar projects.

We also continue to find innovative ways to further integrate our natural gas and natural gas liquids production activities. Well-established business teams, with representatives from across ExxonMobil, work together to ensure that the value of natural gas and natural gas liquids production is maximized through integration with our refining and chemical facilities. For example, in the United Kingdom, we maximize the throughput from our North Sea natural gas liquids extraction plants to provide ethane feedstock to processing facilities at our Fife ethylene plant. In the United States, we also optimize our portfolio of natural gas and natural gas liquids to provide a secure supply for ExxonMobil’s refining and chemical facilities. In North America, we are expanding these activities with the increase in natural gas liquids volumes from liquids-rich unconventional production from our extensive portfolio of resources.

Our internal power requirements also provide another opportunity for integration. Power generation and purchasing expertise enable us to capture additional value while increasing efficiency and reducing emissions. We are an industry leader in the application of cogeneration technology with interests in almost 5 gigawatts of capacity across 100 installations. We continue to pursue cogeneration opportunities around the world to efficiently supply the power and steam demands of ExxonMobil’s Upstream, Downstream, and Chemical facilities. In 2011, we progressed construction of 220 megawatts of additional cogeneration capacity in Singapore. Similar projects in Canada and Europe are in the advanced stages of development.

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Worldwide Upstream Operations

Our portfolio in the Americas includes conventional fields onshore, ultra-deepwater developments, various unconventional gas and oil opportunities, and oil sands and heavy oil plays. Operations in the Americas contributed 31 percent of net oil-equivalent production and 23 percent of Upstream earnings in 2011.

ExxonMobil is a leading reserves holder and producer of oil and natural gas in the United States.

We maintain a significant position in all major producing regions, including the offshore Gulf of Mexico, the Gulf Coast, the mid-continent, California, and Alaska. Technological improvements, operational efficiency, and high-quality drilling programs are extending the lives of our base producing fields, some of which have been onstream for decades. Our portfolio is further augmented by activity in unconventional gas and oil plays and future developments arising from ExxonMobil’s extensive deepwater Gulf of Mexico acreage position.

We produced oil and gas in the offshore Gulf of Mexico with average net production of 57 thousand barrels of liquids per day and 254 million cubic feet of gas per day in 2011.

Over the past two years, we highgraded our Gulf of Mexico portfolio through three separate transactions, including the sale of selected properties to Energy XXI, which closed in late 2010 with operatorship transferred in 2011, the sale of Eugene Island block 314 to Arena Energy in June 2011, and the divestment of XTO Energy’s legacy offshore Gulf of Mexico properties to a private operator in August 2011.

for the Hadrian North oil discovery, which is situated on blocks KC918 and KC919. We also funded the Hadrian South project for subsea tie-back to Anadarko’s Lucius platform with start-up planned for mid-2014. Engineering and technology qualification activities for the Julia discovery (ExxonMobil interest, 50 percent) in Walker Ridge are also progressing.

Additionally, we have a substantial exploration portfolio of 1.3 million net acres in the deepwater Gulf of Mexico and continue to make significant investments in advanced seismic data to further enhance our position. ExxonMobil was also the high bidder on 50 Offshore Continental Shelf (OCS) blocks in Sale 218 held in December 2011.

Conventional • The Mobile Bay development offshore Alabama contributed net production of 137 million cubic feet of gas per day during 2011. We realized significant cost efficiency and environmental benefits in 2011 with the completion of a project to consolidate sour gas treating plants in late 2010.

LNG • The Golden Pass liquefied natural gas (LNG) regasification terminal (ExxonMobil interest, 18 percent) in Sabine Pass, Texas, completed commissioning in June 2011. The terminal has the capacity to supply up to 2 billion cubic feet of natural gas per day to the U.S. market.

ExxonMobil is a leading producer in Louisiana and Texas with a strong position in multiple unconventional gas plays and in the Permian Basin. Onshore net production in Texas and Louisiana added 97 thousand barrels of liquids per day and 2 billion cubic feet of gas per day in 2011.

Conventional • During the year, we shifted drilling activity to liquids opportunities to take advantage of strong realizations. In the liquids-rich Permian Basin, we completed 63 wells across multiple legacy fields, primarily Goldsmith, Russell, and University Block 9. Across our portfolio, we are developing several enhanced oil recovery projects to extend the life of mature assets, including the Means, Talco, and Hawkins fields. The Means Residual Oil Zone project in West Texas commenced in 2011 with the first carbon dioxide injection in December. ExxonMobil also constructed the Hawkins Nitrogen Recovery Unit in 2011, with start-up anticipated in early 2012. We finalized partial unitization of the Talco field in 2011, laying the foundation for future projects. In South Texas, the King Ranch gas plant processed an average of more than 500 million cubic feet of inlet gas per day.

Unconventional • ExxonMobil holds 250,000 net acres in the Haynesville/Bossier Shale of East Texas and Louisiana, one of our strongest onshore production growth areas. Average production more than doubled in 2011, driven by the completion of 66 wells, mainly in the southern core area. By-the-bit drilling success also included completion of seven wells in the overlying Bossier Shale reservoir, which is in place across much of the southern area of the Haynesville play.

In the Barnett Shale play in North Texas, we completed 180 wells in 2011 across a leasehold of 235,000 net acres. Despite a 14-percent increase in per-well measured depth, resulting from longer laterals, we have reduced drilling days per well by 58 percent over the past six years as a result of continuous improvements in efficiency.

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Upstream: Worldwide Upstream Operations, continued

ExxonMobil produces oil and gas throughout the mid-continent states, including Wyoming, Utah, North Dakota, Montana, Colorado, Kansas, Oklahoma, Arkansas, and New Mexico, and the Appalachian states of Pennsylvania and West Virginia. Average net production from these areas in 2011 was 25 thousand barrels of liquids per day and 480 million cubic feet of gas per day.

Conventional • The LaBarge development (ExxonMobil interest, 100 percent) in Wyoming comprises the Madison, Tip Top, and Hogsback fields, and the Shute Creek gas processing plant. It includes the longest sour gas pipeline in the United States and the world’s largest helium recovery and physical solvent gas sweetening plants. The operation celebrated its 25th anniversary in 2011. Implementation of a project to improve environmental performance of the Shute Creek plant’s compressor engines is progressing, with expected start-up in early 2012. The LaBarge facilities processed an average of 705 million cubic feet of inlet gas per day in 2011.

A demonstration plant at the Shute Creek facility tested ExxonMobil’s proprietary Controlled Freeze Zone (CFZ) technology in 2011, with testing continuing in 2012. By using a single-step cryogenic separation process, CFZ could lower the cost of removing carbon dioxide and hydrogen sulfide from natural gas. It could also assist in the application of carbon capture and storage to help reduce greenhouse gas emissions.

Unconventional • Following an acquisition in late 2010 and the completion of 185 wells, gas production from the Fayetteville Shale doubled in 2011. Pad drilling, optimized well spacing, and improved drilling processes are increasing efficiencies as development proceeds on ExxonMobil’s 535,000 net acres of leasehold. For example, using mud drilling instead of air drilling has reduced both well costs and environmental footprint. In addition, a pilot is under way to apply ExxonMobil’s Just-In-Time-Perforating (JITP) fracture stimulation process to horizontal wells, which holds significant potential for further efficiency improvement.

We are involved in several emerging liquids-rich shale plays, the most active of which is the Woodford Shale in the southern Oklahoma Ardmore Basin. By year-end 2011, ExxonMobil established a leadership position of 172,000 net acres in the Woodford Ardmore, and tripled both operated rig count and production. In addition, 31 Ardmore wells were brought on production during the year.

In the tight oil reservoirs of the Bakken Shale, we completed 51 wells in 2011 to delineate multiple core areas across our 395,000 net acre leasehold. We plan to move the play from delineation to development in 2012, using optimized drilling, spacing, and proprietary completion processes.

In the Marcellus Shale, ExxonMobil completed the acquisition of the Phillips Companies in June 2011, which coupled with the purchase of additional assets in West Virginia, increased our Marcellus acreage position to approximately 660,000 net acres. Following these acquisitions and the completion of 38 wells, production in the Marcellus Shale increased more than threefold during the year. In addition, the acquisition of the Phillips Companies provided an entry into the liquids-rich Utica Shale play of eastern Ohio, a position that was increased to roughly 75,000 net acres by year-end 2011 through additional leasing. We expect to drill and complete our first wells in the Utica Shale in 2012.

In Colorado, the Piceance development (ExxonMobil interest, 100 percent) contributed net production of 133 million cubic feet of gas per day in 2011. ExxonMobil has approximately 300,000 net acres under lease in the Piceance Basin. During 2011, we made significant progress to enhance drilling technology to reduce the overall footprint of future drilling well pads, thereby reducing development costs and environmental impacts. For example, we completed the first pitless fracturing operation in October 2011.

Net production from fields both onshore and offshore California averaged 92 thousand barrels of liquids per day and 26 million cubic feet of gas per day during 2011.

The Santa Ynez development (ExxonMobil interest, 100 percent) consists of three platforms located 5 miles offshore Santa Barbara and a processing plant in Las Flores Canyon. We continue to successfully employ world-class extended-reach drilling from these platforms to increase recovery. In offshore California, drilling operations resumed in November 2011 following delays resulting from the Outer Continental Shelf Drilling Moratorium in 2010. In onshore California, continuous single rig drilling commenced in late 2010. ExxonMobil also has a 48-percent equity share in Aera Energy LLC’s operations, comprising eight fields and about 11,000 wells that produce 66 thousand net oil-equivalent barrels per day of a mixture of heavy and conventional oil with associated natural gas.

Average net production in Alaska was 114 thousand barrels of liquids per day in 2011. ExxonMobil is the largest holder of discovered natural gas resources on the North Slope of Alaska. ExxonMobil and the State of Alaska are working on a comprehensive plan to bring Point Thomson on production, including options for full development of Alaska’s gas resources over the long term. ExxonMobil and other working interest owners are identifying resource development alternatives and progressing associated agreements.

We are one of the leading oil and gas producers in Canada through our wholly owned affiliate, ExxonMobil Canada, and majority-owned affiliate Imperial Oil (ExxonMobil interest, 69.6 percent). Through these entities, we have one of the largest resource positions in Canada and possess a significant portfolio of major projects, both onshore and offshore.

The Hibernia field (ExxonMobil interest, 33 percent) offshore Newfoundland is operated by Hibernia Management and Development Company Ltd., using ExxonMobil personnel and processes. Hibernia’s production averaged 154 thousand barrels of oil per day in 2011.

In February 2011, ExxonMobil signed final commercial agreements allowing the co-venturers to proceed with development of the Hibernia Southern Extension project (ExxonMobil interest, 27 percent). The project will include a subsea tieback to the existing Hibernia platform, and will access recoverable resources of approximately 140 million oil-equivalent barrels. Early oil production from platform wells started in June 2011. Contracts were awarded in 2011 and detailed design and fabrication are progressing.

The co-venturer-operated Terra Nova development (ExxonMobil interest, 19 percent) produced 43 thousand barrels of oil per day in 2011. Located in 300 feet of water, Terra Nova consists of a unique, harsh-environment-equipped floating production, storage, and offloading vessel and 28 subsea wells that are expected to recover approximately 400 million oil-equivalent barrels.

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In 2011, the Cold Lake heavy oil field in Alberta (Imperial Oil interest, 100 percent) achieved record production of 160 thousand barrels of oil per day. Cold Lake is the largest thermal in situ heavy oil project in the world. It has over 4000 wells directionally drilled from multiple satellite pads tied back to central facilities, which reduces surface land requirements. Cyclic steam stimulation is used to recover bitumen, and recovery is increased through the use of leading-edge thermal recovery technologies. Engineering is nearing completion and early construction work has commenced on the Nabiye project, the next expansion phase of Cold Lake. Steam injection will produce an additional 40 thousand barrels of bitumen per day at peak rate.

The Syncrude oil sands mining operation (Imperial Oil interest, 25 percent) produced synthetic crude averaging 290 thousand barrels per day in 2011.

The Kearl oil sands project (combined ExxonMobil and Imperial Oil interest, 100 percent) is developing a world-class resource in northern Alberta expected to exceed 4 billion barrels. Construction and fabrication activities are well-advanced on the Kearl Initial Development project with mining and extraction facilities scheduled for start-up by year-end 2012. Initial production will start at approximately 110 thousand barrels of bitumen per day with future debottlenecking and expansion increasing production to 345 thousand barrels of bitumen per day with full development. The Kearl Expansion project was sanctioned in 2011.

We also continue to evaluate oil sands acreage in the Athabasca region with the completion of core hole and seismic programs on both in situ and mining leases in 2011. ExxonMobil acquired an additional 12,000 acres of oil sands leasehold in 2011 through Imperial Oil.

The Mackenzie Gas project received regulatory approvals from the Canadian government in 2011. Once sanctioned, the project will develop three fields (ExxonMobil and Imperial Oil hold interests in two of the three fields) containing approximately 6 trillion cubic feet of natural gas and will deliver natural gas to

In 2011, ExxonMobil and Imperial Oil acquired a 100-percent interest in EL471 and EL472 in the Summit Creek Area of the Northwest Territories. These two blocks cover approximately 444,000 acres and are located near the Imperial Oil-operated Norman Wells field. Planning is currently under way to acquire additional seismic data and drill exploration wells. ExxonMobil and Imperial Oil acquired a 100-percent interest in an additional 56,000 acres in Alberta across a variety of plays. ExxonMobil also successfully tested and began production drilling in a Canadian tight oil play extension in western Alberta in 2011.

ExxonMobil holds a Technical Evaluation Agreement for Block CPE-3 onshore Colombia. The block is located in a remote and unexplored area of the eastern Llanos Basin on trend with the Orinoco heavy oil belt. Stratigraphic core hole drilling to evaluate the prospectivity of this large area commenced in the first quarter of 2012. 2D seismic data acquisition and additional core hole drilling are planned for 2012. If the initial program is successful, we will leverage our extensive global experience in heavy oil development to further evaluate and develop this potential resource.

We have a 50-percent interest in and operate the Stabroek deepwater block (9.6 million acres) offshore Guyana. Interpretation of a newly acquired 2D seismic survey to evaluate prospectivity is under way. Additional 3D seismic acquisition is also planned.

The Cerro Negro and La Ceiba assets of ExxonMobil affiliates were expropriated without compensation by Venezuela on June 27, 2007. Prior to expropriation, ExxonMobil affiliates owned a 41.67-percent interest in Cerro Negro and a 50-percent interest in La Ceiba. ExxonMobil affiliates filed an arbitration against Venezuela with the International Centre for Settlement of Investment Disputes (ICSID) in September 2007. The ICSID arbitration is ongoing. An affiliate filed a related arbitration against Venezuela’s national oil company (PdVSA) and a PdVSA affiliate with the International Chamber of Commerce (ICC) in January

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ExxonMobil is one of the largest producers of oil and gas in Europe. Key activities include North Sea oil and natural gas production and onshore natural gas production. In 2011, Europe accounted for 19 percent of ExxonMobil’s net oil and natural gas production and 21 percent of Upstream earnings.

We continue to progress exploration activities, development projects, and efforts to increase recovery from producing assets through work programs and the implementation of new technology. Frontier exploration activity is also under way. We participated in an exploration well in the Turkish sector of the Black Sea in 2011, and began drilling an exploration well in the Romanian sector of the Black Sea in late 2011. We also continued to progress the evaluation of significant unconventional natural gas and oil opportunities in Germany and Poland. Additionally, ExxonMobil operates liquefied natural gas (LNG) receiving terminals in the United Kingdom and Italy, which provide natural gas supply to the European market.

ExxonMobil is among the largest oil and gas producers in Norway with average net production of 205 thousand barrels of liquids per day and 663 million cubic feet of gas per day in 2011.

We operate producing fields in Norway including Ringhorne (ExxonMobil interest, 100 percent), Ringhorne East (ExxonMobil interest, 77 percent), and Balder (ExxonMobil interest, 100 percent), which are located 110 miles west of Stavanger. Since coming onstream in 2003, Ringhorne has produced over 200 million oil-equivalent barrels. In 2011, production averaged 39 thousand oil-equivalent barrels per day. We continued drilling operations from the Ringhorne platform in 2011, following a successful 4D seismic program in 2010. We plan to extend the 4D seismic coverage in 2012 to support continued Ringhorne drilling. A multiyear drilling program is also planned for the Balder field.

Conceptual engineering was completed in 2011 for the Dagny (ExxonMobil interest, 33 percent) and Luva (ExxonMobil interest, 15 percent) offshore development projects with front-end engineering design (FEED) planned in 2012 for both projects.

ExxonMobil participates in the ASC project (ExxonMobil interest, 13.5 percent) in the Aasgard area, which will maximize recovery from the Mikkel and Midgard fields by installing subsea compression near Midgard to maintain stable flow rates in the two flowlines. This project is in the execution phase and represents an industry first in the application of subsea compression.

In May 2011, we acquired a 35-percent-operated interest in the PL596 Møre Vest license, covering 787,000 acres, and a 30-percent interest in the PL598 Ygg High license, covering 409,000 acres in the Norwegian Sea. In both licenses, the primary objective is located beneath basalt that will require the application of specialized sub-basalt imaging technology to identify structures for future drilling. We acquired new ocean bottom cable seismic on PL596 in September 2011. Additional seismic programs are planned on both licenses during 2012. ExxonMobil is also the operator of PL520 (ExxonMobil interest, 50 percent) in the Norwegian Sea. The license covers 736,000 acres in water depths ranging from 4200 to 7800 feet. Processing of 3D seismic data acquired in 2010 continued during 2011. We will use this data to identify potential drilling opportunities.

During 2011, we sold our interests in the Beryl field and associated subsea fields of Nevis, Ness, Buckland, and Skene (ExxonMobil interest, 50 percent) in the North Sea, the Scottish Area Gas Evacuation (SAGE) plant at St. Fergus and the associated Beryl/Brae gas pipeline, and the Benbecula exploration acreage west of Shetland to Apache. ExxonMobil continues to have significant equity participation in over 40 U.K. producing fields in the North Sea, principally through a Shell/Esso joint venture.

Conceptual engineering was completed and front-end engineering design commenced in 2011 for the Fram offshore development project (ExxonMobil interest, 72 percent; and 50 percent for two licenses currently under unitization).

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ExxonMobil is one of the largest natural gas producers in the Netherlands, primarily through our shareholding in NAM (Nederlandse Aardolie Maatschappij), a 50-percent ExxonMobil equity company that produces gas from more than 100 fields located both onshore and offshore. Our net production in the Netherlands averaged 1.8 billion cubic feet of gas per day in 2011. The majority of this production comes from the Groningen field (ExxonMobil interest, 30 percent), which is Europe’s largest natural gas field.

NAM’s Schoonebeek Redevelopment project (ExxonMobil interest, 30 percent) came online in early 2011 and is expected to recover 120 million barrels of oil.

The Adriatic LNG Terminal (ExxonMobil interest, 71 percent) located 10 miles offshore of Porto Levante, Italy, in the northern Adriatic Sea, is the world’s first fixed offshore LNG storage and regasification terminal. The terminal has capacity to supply up to 775 million cubic feet of gas per day to the Italian market, approximately 10 percent of Italy’s natural gas demand. In 2011, 81 cargoes were delivered to the terminal totaling 5.5 million tonnes of LNG.

We sold our 25-percent interest in the Tempa Rossa joint venture and our 51.7-percent interest in the adjacent exploration licenses to Total in September 2011.

Faroe Islands • In March 2011, ExxonMobil acquired a 49-percent interest in license L006 and a 50-percent interest in licenses L009 and L011, covering 1.1 million acres. The Statoil-operated Brugdan-2 wildcat well on license L006 is planned for 2012.

Romania • We have a 50-percent interest in the 1.9 million-acre deepwater Neptun Block in the Black Sea. Processing of 3D seismic and other 2D seismic data continued during 2011 to identify potential drilling opportunities. Exploration drilling began in late 2011.

Ireland • ExxonMobil has interests in two exploration licenses (ExxonMobil interest in Dunquin, 27.5 percent; ExxonMobil interest in Cuchulain, 36 percent) covering almost 704,000 acres in the Porcupine Basin, located 125 miles off the southwest coast of Ireland. During 2011, we farmed out 12.5 percent of our equity in the Dunquin license to Repsol and relinquished interests in two other licenses, Drombeg and Drombeg Extension. Drilling is planned on the ExxonMobil-operated Dunquin license in 2013.

Turkey • ExxonMobil has interests in two licenses covering more than 15 million acres in the Turkish Black Sea in water depths ranging from 450 to 7250 feet. We operate the Kastamonu sub-block of license 3921 and the Samsun sub-block of license 3922 with a 50-percent interest. We also have a 25-percent interest in each of the Sinop, Ayancik, and Carsamba sub-blocks of the Petrobras-operated license 3922. The ExxonMobil-operated Kastamonu-1 wildcat was the first well drilled on license 3921 and was plugged and abandoned in 2011.

Poland • We have an interest in six licenses in the Podlasie and Lublin Basins of eastern Poland covering approximately 1.6 million acres (100-percent interest in the four Podlasie licenses and a 51-percent interest in the two Lublin licenses following a farm-out of 49 percent of our equity to Total in 2011). We acquired and processed a program of 2D and 3D seismic during 2011. The ExxonMobil-operated Krupe-1 and Siennica-1 shale gas wildcat wells were drilled in 2011.

Greenland • In the West Disko area offshore western Greenland, we have interests in Block 6 (ExxonMobil interest, 44 percent) and Block 4 (ExxonMobil interest, 29 percent) totaling 6.7 million acres. Geological evaluation and environmental activities continued on these blocks in 2011.

Deepwater Champion drillship passing through the Bosporus Strait on its way to drill ExxonMobil’s first well in the Turkish Black Sea.

5 billion oil-equivalent barrels on the block. The Xikomba field started production in November 2003, followed by start-ups of Kizomba A in 2004, Kizomba B in 2005, and Kizomba C in 2008. Production from the depleted Xikomba field ended in 2011, and all FPSO production facilities were cleaned and abandoned. With daily output of more than 440 thousand barrels of oil, Block 15 was Angola’s second-highest-producing block during the year, and facilities continue to operate with very high levels of reliability.

Additional Block 15 developments continue to progress in 2011, including the Gas Gathering and Kizomba Satellites projects. The Gas Gathering project initiated supply of Block 15 gas to the Angola LNG facility in Soyo. Execution activities are progressing on the Kizomba Satellites Phase 1 project that will include subsea tiebacks to the Kizomba A and B floating production, storage, and offloading (FPSO) vessels. The project is expected to recover nearly 250 million barrels of oil and is anticipated to start production in 2012. Through collaborative development efforts, we continue to utilize the local workforce to enhance Angolan industrial capabilities and competitiveness. Development planning continues for several of the remaining discovered resources on Block 15, including Kizomba Satellites Phase 2 and the 2009 Mondo South discovery.

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ExxonMobil • 2011 Financial & Operating Review

offloading (FPSO) vessel to produce up to 220 thousand barrels of oil per day. The next development within Block 17 is Cravo-Lirio-Orquidea-Violeta (CLOV) (ExxonMobil interest, 20 percent), which was sanctioned by the co-venturers in 2010. Project execution activities for CLOV continued in 2011. CLOV is located in 4100 feet of water and will use an FPSO vessel to produce 160 thousand barrels of oil per day. The Tulipa-2 exploration well commenced drilling in October 2011 and is targeting resources to support future development plans.

Block 31 • We were awarded a 25-percent interest in Block 31 in 1999, and the first discovery on the block occurred in 2002. Through year-end 2011,19 discoveries have been announced with a total resource of approximately 2 billion oil-equivalent barrels. The first development on the block is the Plutao-Saturno-Venus-Marte (PSVM) hub located in the northern part of the block in water depths ranging from 5900 to 6700 feet. A 150-thousand-barrel-per-day FPSO vessel conversion is under construction to produce an estimated 490 million barrels of oil. Planning is progressing for development of an additional hub in the southeastern and central parts of the block. As part of our portfolio optimization efforts, ExxonMobil is advancing the sale of our equity interest in Block 31.

Block 32 • Development planning activities continue for Block 32 where ExxonMobil owns a 15-percent interest. Through year-end 2011,12 discoveries have been announced with a total resource of approximately 1.4 billion oil-equivalent barrels on the block. The first FPSO vessel development planned for Block 32 is the Kaombo Split Hub in the southeastern part of the block, with estimated recovery of about

Erha/Erha North • The Erha development (ExxonMobil interest, 56 percent) is located 60 miles offshore in 3900 feet of water. Erha and Erha North, ExxonMobil’s first operated deepwater production in Nigeria, started in 2006. The development consists of more than 30 subsea wells tied back to a floating production, storage, and offloading (FPSO) vessel, with a capacity in excess of 200 thousand barrels per day.

The Erha North Phase 2 project (ExxonMobil interest, 56 percent) is a subsea tieback to the existing Erha FPSO vessel. The project will further develop the currently producing Erha North field, with a peak production rate of approximately 60 thousand barrels of oil per day. Engineering, procurement, and construction (EPC) contracting for the project is progressing.

Bosi • The Bosi development (ExxonMobil interest, 56 percent) is planned as a spread-moored FPSO vessel with associated subsea developments. The Bosi project phases are expected to develop approximately 500 million barrels of oil and up to 2.5 trillion cubic feet of natural gas. Project concept selection activities are progressing in participation with the Nigerian government and co-venture partner, Shell.

Bonga Northwest • Bonga Northwest (ExxonMobil interest, 20 percent) is planned as a subsea tieback to the existing Bonga FPSO vessel, which began production from the Bonga field in 2005. Project execution activities continue on Bonga Northwest, which is expected to develop approximately 125 million barrels of oil.

Bonga North • The Bonga North development (ExxonMobil interest, 20 percent) is planned as multiple subsea wells tied back to an FPSO vessel. Front-end engineering and design continues on the Bonga North subsea architecture. It is anticipated that this project will develop more than 350 million barrels of oil.

Bonga Southwest • The Bonga Southwest project (ExxonMobil interest, 16 percent) is planned as an FPSO vessel development with a dedicated gas export pipeline. The project is anticipated to develop more than 800 million barrels of oil.

Usan • Project execution continues on the Usan project (ExxonMobil interest, 30 percent) located 60 miles offshore Nigeria in 2500 feet of water. Full development, including future phases, is designed to recover up to 500 million barrels of oil using subsea wells connected to a 180-thousand-barrel-per-day capacity FPSO vessel. Major contracts were awarded in early 2008, and development drilling and offshore installation were progressed in 2011. Start-up is expected in early 2012.

OPL 223 • Following the Owowo South-1 discovery in 2009, we entered into the second exploration phase in OPL 223 (ExxonMobil interest, 27 percent) beginning in July 2010. Exploration drilling is planned for 2012.

OPL 214 • We were awarded operatorship of OPL 214 in 2001 (ExxonMobil interest, 20 percent) and discovered the Uge field in 2005. Development planning for Uge continues. Phase III exploration drilling commenced in late 2011 and will continue through early 2012 before conversion to an oil mining license (OML) in 2012.

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ExxonMobil’s portfolio on the Nigerian shelf includes 69 fields. We have ongoing activities to increase liquids volumes, including an active development drilling program, installation of new platforms, enhanced oil recovery projects, and a series of platform upgrades. In addition, seismic and exploration activities continue in an effort to identify new opportunities within the joint venture.

Ocean bottom cable seismic data were acquired in 2010, and additional seismic acquisition is planned for 2013. Joint venture exploration drilling is also planned.

Natural Gas Liquids • Natural gas liquids plants along with pressure maintenance projects significantly reduce flaring and greenhouse gas emissions while improving oil recovery through reservoir pressure maintenance. Production of natural gas liquids began in 1998 with the OSO Natural Gas Liquids project and grew in 2008 with the East Area Natural Gas Liquids II project (ExxonMobil interest, 51 percent). Production from these two projects averaged 34 thousand barrels per day in 2011. The projects are expected to recover about 400 million barrels of natural gas liquids. In addition, they have contributed to a 70-percent reduction in flaring since 2007.

Satellite Field Development • Execution of ExxonMobil’s “design one, build multiple” approach for the Satellite Field Development project (ExxonMobil interest, 40 percent) is progressing. Phase 1 is under way with installation of three platforms currently planned for 2012. These additional offshore facilities will allow drilling in undeveloped areas of the joint venture and provide pipeline connections back to existing infrastructure. Peak production from Phase 1 is anticipated to reach 70 thousand barrels of liquids per day.

Domestic Power Generation and Natural Gas Supply • In 2011, ExxonMobil completed front-end engineering and design work for a joint venture project to construct a 500-megawatt power plant. The project is a component of an integrated plan to increase gas utilization and power generation capacity in Nigeria. In addition, the joint venture is constructing new facilities that will allow for delivery of natural gas to Nigeria’s domestic market.

ExxonMobil operates the Zafiro field in Equatorial Guinea (ExxonMobil interest, 71 percent) in water depths between 400 and 2800 feet. In 2011, net production averaged 45 thousand barrels of oil per day. A successful multiyear drilling program came to an end in 2011 with the addition of more than 25 million barrels of reserves. We continue to progress discussions with the government of Equatorial Guinea on projects aimed at enabling a reduction in flaring and the development of Zafiro gas resources. 2011 represented the 15th year of production from the Zafiro field during which more than 800 million barrels have been produced.

Chad

ExxonMobil began production in 2003 and is the leading oil producer in Chad (ExxonMobil interest, 40 percent), with average net production of 40 thousand barrels of oil per day in 2011. An active two-rig development drilling program continued in 2011, focused on the Kome, Bolobo, and Miandoum fields.

Republic of Congo • Through year-end 2011, five discoveries were announced in the Mer Tres Profonde Sud block (ExxonMobil interest, 30 percent) with a total resource of approximately 400 million oil-equivalent barrels. Additional exploration activity is planned in 2012.

Madagascar • ExxonMobil holds an interest in approximately 1.8 million acres in the Majunga Basin offshore Madagascar. We continue to closely monitor political developments in Madagascar, with exploration activities and drilling operations currently suspended.

Libya • We relinquished our interest in Contract Area 44 in Libya in November 2010. We also concluded studies in Contract Areas 20 and 21.

Tanzania • ExxonMobil entered Tanzania in 2010 by acquiring a 35-percent working interest in deepwater Block 2. A 3D seismic survey, acquired in 2010, is being interpreted to identify potential drilling prospects. The Zafarani-1 exploration well started drilling in January 2012 and, if successful, may result in the drilling of a second exploration well, Lavani-1.

In Asia, ExxonMobil is participating in the development of some of the world’s largest oil and gas prospects. Our production grew significantly in 2011 with the continued ramp-up of the Qatar projects. Overall, ExxonMobil operations in the Asia region contributed 37 percent to our net oil and gas production and 39 percent to Upstream earnings.

Through the Qatar joint ventures, Qatar Petroleum and ExxonMobil continue to develop the North Field, the largest non-associated gas field in the world. These efforts will develop resources exceeding 25 billion oil-equivalent barrels through a suite of projects. ExxonMobil participates in all seven of the RasGas liquefied natural gas (LNG) trains and in five of the Qatargas LNG trains (ExxonMobil interest ranges from 10 to 34 percent). LNG production from ExxonMobil-interest trains in Qatar was 62 million tonnes in 2011. The Al Khaleej Gas facilities produced about 1.7 billion cubic feet per day in 2011, providing supplies primarily to the domestic market. ExxonMobil is also participating in the Barzan Gas project, which is expected to supply 1.4 billion cubic feet per day to the Qatar gas market.

Qatargas • We participate in the Qatargas 1 and Qatargas 2 joint ventures with interests ranging from 10 to 30 percent. Qatargas 1 consists of three trains with a total nominal capacity of 9.9 million tonnes per year, delivering LNG primarily to Japan and Spain. Qatargas 2, which started up in 2009, consists of two 7.8-million-tonne-per-year trains. These operations also produce associated products including condensate, liquefied petroleum gas (LPG), helium, and sulfur. Deliveries of LNG from Qatargas 2 utilize a fleet of Q-Flex and Q-Max vessels, the world’s largest LNG carriers. Shipments are delivered primarily to the United Kingdom through the South Hook LNG Terminal.

RasGas • RasGas is a joint operating company comprised of Qatar Petroleum and ExxonMobil, with 70-percent and 30-percent interests, respectively. The 7.8-million-tonne-per-year Train 7 started up in 2010, increasing total RasGas LNG production capacity to 36 million tonnes per year. LNG from the seven trains is primarily sold to the Asian and European markets. In addition to LNG, RasGas also produces considerable amounts of associated products including condensate, liquefied petroleum gas, helium, and sulfur.

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Barzan • In 2007, Qatar Petroleum and ExxonMobil signed a Heads of Agreement (HOA) to jointly develop the Barzan project. In January 2011, a joint venture agreement, along with development and fiscal agreements, was signed for the initial phase of the project. This phase will supply up to 1.4 billion cubic feet per day of domestic natural gas to meet demand driven by Qatar’s rapidly growing infrastructure and industry requirements. Detailed engineering and early onshore construction activities are progressing. Early offshore development drilling is also under way.

ExxonMobil holds two oil concessions in the United Arab Emirates. In 2011, net production from the onshore oil concession was 127 thousand barrels of oil per day. Net production from the Upper Zakum offshore concession was 151 thousand barrels of oil per day.

With our ability to deliver superior technology and project execution excellence, we gained entry into Upper Zakum (ExxonMobil interest, 28 percent) in 2006. Upper Zakum is one of the world’s largest oil fields, with an initial resource estimate of approximately 50 billion barrels of oil. The offshore Upper Zakum field covers more than 450 square miles and has production capacity of more than 550 thousand barrels per day. Along with our partners in the joint venture, we are applying leading-edge technology that will boost daily field production capacity by an additional 200 thousand barrels per day. Construction is under way on artificial islands that will utilize extended-reach drilling to help increase recovery at a lower cost. Front-end engineering and design activities are complete, and contracting activities are progressing.

ExxonMobil signed agreements with the South Oil Company (SOC) of the Iraqi Ministry of Oil in 2010 to redevelop and expand production from the West Qurna I oil field in southern Iraq (ExxonMobil interest, 60 percent) and to develop additional discovered but undeveloped reservoirs within the contract area. Located in one of Iraq’s most prolific producing areas, field redevelopment and expansion will entail extensive infill drilling, reservoir pressure support, new production facilities, and associated support infrastructure. Our project execution experience and global procurement network will play a critical part in maximizing the value of this resource.

Since signing the agreements, we established offices in both Baghdad and Basra and awarded contracts for engineering services, drilling, workovers, power, and water. The West Qurna I project achieved the Initial Production Target in April 2011, representing a 10-percent increase in production and triggering cost recovery. At year-end 2011, production from the West Qurna I field was about 370 thousand gross barrels per day, representing an increase of over 50 percent since the contract was awarded.

ExxonMobil also led a group of international oil and Iraqi state companies in the study of the development of a large seawater supply facility on the Iraqi coast of the Arabian Gulf. This facility would supply seawater for pressure support for West Qurna I as well as most of the other large oil fields in southern Iraq. We are working with the Iraq Ministry of Oil, SOC, and other international oil company participants to establish the commercial and technical basis for this project.

In addition, in October 2011, we signed six production sharing contracts (PSC) (ExxonMobil interest, 100 percent) covering 848,000 gross acres in the Kurdistan Region of Iraq.

Daily production from Chayvo and Odoptu averaged 163 thousand barrels of oil and 164 million cubic feet of natural gas in 2011. Since the initial start-up of Sakhalin-1 in 2005, almost 340 million barrels of oil have been produced and exported to world markets.

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Tengiz • ExxonMobil participates in the Tengizchevroil (TCO) joint venture (ExxonMobil interest, 25 percent), which includes a production license area encompassing the super giant Tengiz field, an associated processing plant complex, and the nearby Korolev field. TCO holds a total of 380,000 acres. The Tengiz field has produced more than 1.8 billion barrels of oil from a total resource of nearly 6 billion barrels. In 2011, TCO achieved new record production rates in excess of 635 thousand barrels of oil per day. The TCO joint venture continues to invest in projects to improve the reliability and integrity of existing facilities. TCO is progressing a project to extend current production rates as reservoir pressure declines and is also considering the potential for a major expansion project.

Kashagan • As a participant in the North Caspian Production Sharing Agreement (ExxonMobil interest, 17 percent), we are working with consortium members to progress phased development of the massive Kashagan field located offshore in the Caspian Sea. Phase 1 includes an offshore production and separation hub on an artificial island, several drilling islands, and an onshore processing plant. The facilities for commercial production are 95 percent complete, and drilling is progressing according to plan. Plans for future phases are under evaluation.

Caspian Pipeline Consortium • The Caspian Pipeline Consortium (ExxonMobil interest, 7.5 percent), broke ground on an expansion project that will increase system capacity from 0.6 to 1.4 million barrels per day and will run from Kazakhstan to the Novorossiysk marine terminal on the Russian Black Sea coast. Construction is under way with expansion capacity being delivered in phases from the beginning of 2013 through 2015. This pipeline system represents the lowest-cost export option for Kazakhstan, with both Tengizchevroil and future Kashagan developments as major shippers.

ExxonMobil operates the onshore Arun and Arun satellite fields and the North Sumatra offshore field that supply natural gas to the PT Arun LNG plant. In 2011, net production from these fields averaged 164 million cubic feet of gas per day and 1.7 thousand barrels of associated liquids per day.

In 2009, early oil production facilities were brought online for the Banyu Urip development in the Cepu Contract Area, onshore Java (ExxonMobil interest, 45 percent). Production through the early oil facility averaged 21 thousand barrels per day in 2011. Full field development is progressing and

will produce 165 thousand barrels of oil per day and include 49 wells, an onshore central processing facility, and a 60-mile pipeline that will transport oil to a floating storage and offloading vessel. All engineering, procurement, and construction (EPC) contracts were awarded in 2011. We also made two discoveries in the Cepu block in 2011. The Alas Tua West-1 well discovered gas and the Kedung Keris-1 well discovered a 561-foot oil column. Additional Cepu exploration drilling is planned for 2012.

In August 2011, we signed a Heads of Agreement (HOA) with Pertamina that included principles for unitization of the Jambaran and Tiung Biru gas fields and the appointment of PT Pertamina EP Cepu as the operator of the Jambaran-Tiung Biru unit. The Cepu producers are working to optimize the development and commercialization of gas resources from the Cepu block and support Indonesia’s priorities to meet domestic energy needs.

In 2008, ExxonMobil submitted a Plan of Development to the government of Indonesia and communicated intention to enter the next phase of development for the large offshore gas field within the Natuna D-Alpha PSC, which contains more than 70 percent carbon dioxide. Development activities commenced in 2009, and technical activities continue.

On December 3, 2010, ExxonMobil and Pertamina signed a Heads of Agreement (HOA) that provides the basis for negotiating a new East Natuna Area Production Sharing Contract (PSC) and Joint Operating Agreement (JOA). Following the HOA, ExxonMobil, Pertamina, Total, and Petronas signed a Principles of Agreement (POA) on August 19, 2011. The POA tabled key terms, working area, and a schedule to negotiate a new PSC. Negotiations are progressing toward completion of a new PSC.

Exploration drilling commenced in early 2011 to test coal bed methane potential in the Barito Basin in Kalimantan (ExxonMobil interest, 49 percent). Five wells were drilled by year end, and exploration evaluation will continue in 2012.

Work also continued on the deepwater Cendrawasih block offshore West Papua, with collection and processing of an aeromagnetic survey. Drop cores were also collected in late 2011 as studies continue for a potential wildcat well in 2013.

ExxonMobil operates 43 platforms in 17 fields as one of Malaysia’s major suppliers of crude oil and natural gas. Net production in 2011 averaged 38 thousand barrels of liquids per day and 420 million cubic feet of gas per day.

During 2011, design work was completed for the Tapis field Enhanced Oil Recovery and Telok Gas projects, and fabrication of associated offshore facilities commenced. In addition, we continued with development planning work on both the Guntong field Enhanced Oil Recovery and Damar Gas projects. The Damar Gas project along with the Telok Gas project will provide additional gas supplies for Malaysia’s power and industrial needs.

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	40

Upstream: Worldwide Upstream Operations, continued

ExxonMobil is a leading oil and gas producer in the Australia/Oceania region. In 2011, net production averaged 51 thousand barrels of liquids and 331 million cubic feet of gas per day. The majority of our current production in the region is from the offshore Gippsland Basin in Australia. Future volume contribution from this region is anticipated to grow with the start-up of the Papua New Guinea (PNG) and Gorgon Jansz liquefied natural gas (LNG) projects.

The Kipper Tuna and Turrum projects are new developments in the Gippsland Basin (ExxonMobil interest, Kipper 32.5 percent, Tuna and Turrum 50 percent) consisting of installation of an additional offshore platform (Marlin B) and a subsea tie back to existing facilities. During 2011, significant progress was made in the offshore installation phase of the projects with the laying of all subsea equipment and pipelines and the setting of the Marlin B jacket.

Execution activities continued on the 15-million-tonne-per-year Gorgon Jansz LNG project (ExxonMobil interest, 25 percent), which will develop 25 trillion cubic feet of offshore gas resources. The development consists of a subsea infrastructure for offshore production and transportation of the gas, three 5-million-tonne-per-year LNG trains, and a 280-million-cubic-feet-per-day domestic gas plant located on Barrow Island, as well as the world’s largest carbon dioxide sequestration project. The project is well under way with significant progress made on Barrow Island to prepare the LNG facility site. Construction of LNG equipment modules and structures is also under way in South Korea, China, and Indonesia. Other project activities are progressing as well, including offshore drilling of the Gorgon wells, offshore pipeline construction, and construction of subsea production equipment in the United Kingdom.

ExxonMobil, as work operator for Jansz-lo drilling and completion, is finalizing detailed engineering and operations planning for the Jansz-lo field development. The gas will be produced via one of the world’s longest subsea tiebacks, located in 4300 feet of water. The first Gorgon Jansz LNG shipment is targeted for late 2014.

In 2011, we participated in an appraisal drilling program in the Greater Gorgon area aimed at maturing additional gas resources for a potential expansion of the Gorgon project. Appraisal wells were drilled on the Orthrus, Chandon, Chrysaor, and West Tryal Rocks fields.

Development and execution planning continues for the Scarborough LNG project (ExxonMobil interest, 50 percent). The field is located offshore western Australia in 3100 feet of water and has a resource of up to 10 trillion cubic feet of gas.

In 2011, ExxonMobil participated in three wells on the Northwest Shelf (ExxonMobil interest, 25 percent). Orthrus Deep encountered gas in untested intervals below the existing Orthrus discovery on retention lease WA-24-R. The Zagreus wildcat on WA-40-L near the Jansz-lo field did not encounter hydrocarbons. The third well in the 2011 program, Satyr-3, started drilling in December 2011 and is a follow-up to the successful 2009 Satyr-1 discovery well located in WA-374-P. Additional wildcats are planned for 2012.

In 2011, ExxonMobil’s net production from Papua New Guinea averaged 6 thousand barrels of oil per day and 4 million cubic feet per day of gas.

The Papua New Guinea (PNG) liquefied natural gas (LNG) project (ExxonMobil interest, 33 percent) is progressing toward a 2014 start-up. Following site preparations and road and infrastructure development over the past year, the project celebrated the first weld on the 430-mile onshore/offshore gas pipeline and completed shipping and offloading of 40,000 sections of pipe. The sections will be used in the construction of the 180-mile onshore portion of the gas pipeline. The first drilling rig was also completed and shipped to PNG in 2011. Construction of the LNG plant process train pipe racks, storage tanks, foundations, and jetty are all under way.

As part of the project, ExxonMobil continues to grow our Papua New Guinean project workforce. At year-end 2011, the project workforce exceeded 14,000. More than 60 percent of the workforce are Papua New Guinean citizens.

The expertise of Papua New Guinean workers is being developed through dedicated facilities such as the Port Moresby Construction Training Facility. To date, ExxonMobil and our contractors have trained more than 6000 Papua New Guinean citizens for construction, support, and future production roles. This equates to more than 900,000 hours of training as of the end of 2011.

Support for developing Landowner Companies (Lancos) continues, with the assistance of business development officers in the field, the Enterprise Centre, and project contractors. Project-related spending with Lancos by year-end 2011 was approximately $300 million. Papua New Guinean businesses other than Lancos are also providing goods and services to the project. The project’s total in-country spend to date was close to $1.7 billion. The Enterprise Centre, established in partnership with the PNG Institute of Banking and Business Management, celebrated its first anniversary in 2011. The Centre has supported 10,000 Papua New Guinean businesses and achieved more than 3750 days of training in an effort to foster supplier development for the project and future economic development in PNG.

In addition to project activities, we continued acquisition of a multiyear 2D seismic program in the PNG highlands, in advance of planned exploration drilling in 2012.

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(thousands of barrels per day)		2011				2010				2009				2008				2007
United States
Alaska			114				117				123				130				132
Lower 48			309				291				261				237				260
Total United States			423				408				384				367				392
Canada/South America			252				263				267				292				324
Total Americas			675				671				651				659				716
Europe
United Kingdom			55				80				90				123				150
Norway			205				246				280				295				319
Other			10				9				9				10				11
Total Europe			270				335				379				428				480
Africa
Nigeria			324				391				391				364				415
Angola			99				141				194				181				173
Equatorial Guinea			45				53				55				60				76
Other			40				43				45				47				53
Total Africa			508				628				685				652				717
Asia
Malaysia			38				48				52				56				67
Middle East			567				478				368				381				374
Russia/Caspian			191				191				182				160				185
Other			12				13				5				2				3
Total Asia			808				730				607				599				629
Australia/Oceania			51				58				65				67				74
Total worldwide			2,312				2,422				2,387				2,405				2,616
Gas Plant Liquids Included Above
United States			78				59				50				49				57
Non-U.S.			213				207				173				164				166
Total worldwide			291				266				223				213				223
Oil Sands and Non-Consolidated Volumes Included Above
United States			66				69				73				78				82
Canada/South America – Bitumen			120				115				120				124				130
Canada/South America – Synthetic Oil			67				67				65				62				65
Europe			5				5				5				5				6
Asia			425				404				320				280				265
Total worldwide			683				660				583				549				548

(1)		Net liquids production quantities are the volumes of crude oil and natural gas liquids withdrawn from ExxonMobil’s oil and gas reserves, excluding royalties and quantities due to others when produced, and are based on the volumes delivered from the lease or at the point measured for royalty and/or severance tax purposes. Volumes include 100 percent of the production of majority-owned affiliates, including liquids production from oil sands operations in Canada, and ExxonMobil’s ownership of the production by companies owned 50 percent or less.

 

(millions of cubic feet per day)		2011				2010				2009				2008				2007
United States			3,917				2,596				1,275				1,246				1,468
Canada/South America			412				569				643				640				808
Total Americas			4,329				3,165				1,918				1,886				2,276
Europe
Netherlands			1,826				2,041				1,676				1,748				1,551
United Kingdom			441				550				594				750				779
Norway			663				700				786				764				705
Germany			518				545				633				687				775
Total Europe			3,448				3,836				3,689				3,949				3,810
Africa			7				14				19				32				26
Asia
Indonesia			164				215				245				239				286
Malaysia			420				513				545				582				583
Middle East			4,261				3,865				2,367				1,911				1,875
Russia/Caspian			184				187				153				114				110
Other			18				21				22				24				29
Total Asia			5,047				4,801				3,332				2,870				2,883
Australia/Oceania			331				332				315				358				389
Total worldwide			13,162				12,148				9,273				9,095				9,384
Non-Consolidated Natural Gas Volumes Included Above
United States			–				1				1				1				1
Europe			1,747				1,977				1,618				1,696				1,503
Asia			3,168				2,954				1,918				1,433				1,351
Total worldwide			4,915				4,932				3,537				3,130				2,855

(1)		Net natural gas available for sale quantities are the volumes withdrawn from ExxonMobil’s natural gas reserves, excluding royalties and volumes due to others when produced, and excluding gas purchased from others, gas consumed in producing operations, field processing plant losses, volumes used for gas lift, gas injection and cycling operations, quantities flared, and volume shrinkage due to the removal of condensate or natural gas liquids fractions.

(millions of cubic feet per day)		2011				2010				2009				2008				2007
United States			5,002				3,166				1,321				1,292				1,560
Canada/South America			517				696				739				845				968
Europe			6,254				6,401				5,854				5,665				5,396
Africa			7				14				19				32				26
Asia			4,289				4,102				2,760				2,612				2,631
Australia/Oceania			338				339				322				366				398
Total worldwide			16,407				14,718				11,015				10,812				10,979

(1)		Natural gas sales include 100 percent of the sales of ExxonMobil and majority-owned affiliates and ExxonMobil’s ownership of sales by companies owned 50 percent or less. Numbers include sales of gas purchased from third parties.

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NUMBER OF NET WELLS DRILLED ANNUALLY(1)
(net wells drilled)			2011				2010				2009				2008				2007
Productive
Exploratory(2)			25				37				20				19				19
Development			1,554				1,200				829				731				917
Total			1,579				1,237				849				750				936
Dry
Exploratory(2)			11				7				9				9				16
Development			16				5				5				4				19
Total			27				12				14				13				35
Net Wells Drilled
Exploratory(2)			36				44				29				28				35
Development			1,570				1,205				834				735				936
Total			1,606				1,249				863				763				971
NET ACREAGE AT YEAR END(3)
(thousands of net acres)			2011				2010				2009				2008				2007
Undeveloped
United States			5,326				4,914				5,111				5,691				5,539
Canada/South America			9,877				11,977				17,107				19,953				22,563
Europe			16,107				16,118				13,470				7,913				6,002
Africa			8,100				8,612				10,555				26,439				24,835
Asia			19,919				19,086				20,457				6,824				7,715
Australia/Oceania			1,476				1,352				5,216				5,738				5,844
Total worldwide			60,805				62,059				71,916				72,558				72,498
Developed
United States			10,311				9,919				5,120				5,148				5,174
Canada/South America			1,959				2,439				2,460				2,488				2,366
Europe			2,868				2,986				3,806				4,026				4,194
Africa			700				684				758				756				729
Asia			1,230				1,271				1,160				1,048				1,037
Australia/Oceania			719				719				719				719				728
Total worldwide			17,787				18,018				14,023				14,185				14,228
NET CAPITALIZED COSTS AT YEAR END(3)
(millions of dollars)			2011				2010				2009				2008				2007
United States			76,363				70,011				20,363				18,542				16,948
Canada/South America			21,721				18,089				13,408				9,967				11,338
Europe			11,399				12,845				14,357				11,477				15,426
Africa			24,790				22,563				20,917				17,797				15,149
Asia			25,594				23,765				21,859				19,191				17,186
Australia/Oceania			6,864				5,284				3,725				2,407				2,630
Total worldwide			166,731				152,557				94,629				79,381				78,677