Statements of future events or conditions
in this report, including projections, targets,
expectations, estimates, and business plans, are
forward-looking statements. Actual future results,
including demand growth and energy mix; capacity
growth; the impact of new technologies; capital
expenditures; project plans, dates, costs, and capacities;
production rates and resource recoveries; efficiency gains;
cost savings; product sales; and financial results could differ
materially due to, for example, changes in oil and gas prices
or other market conditions affecting the oil and gas industry;
reservoir performance; timely completion of development
projects; war and other political or security disturbances; changes
in law or government regulation; the actions of competitors and
customers; unexpected technological developments; the occurrence
and duration of economic recessions; the outcome of commercial
negotiations; unforeseen technical difficulties; unanticipated
operational disruptions; and other factors discussed in this report
and in Item 1A of ExxonMobil’s most recent Form 10-K.

Definitions of certain financial and operating measures and other terms used
in this report are contained in the section titled “Frequently Used Terms” on
pages 93 through 95. In the case of financial measures, the definitions also
include information required by SEC Regulation G.

“Factors Affecting Future Results” and “Frequently Used Terms” are also available on
the “investors” section of our website.

Prior years’ data have been reclassified in certain cases to conform to the 2012 presentation basis.

The term “project” as used in this publication does not necessarily have the same meaning as under SEC Rule 13q-1 relating to government
payment reporting. For example, a single project for purposes of the rule may encompass numerous properties, agreements, investments,
developments, phases, work efforts, activities, and components, each of which we may also informally describe herein as a “project.”

 

2			EXXONMOBIL  2012 FINANCIAL & OPERATING REVIEW
	Our competitive advantages formed the framework for solid financial and operating results across all key measures and businesses in 2012. 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. Rex W. Tillerson, Chairman and CEO

 

Functional Earnings and Net Income(2)		Return on Average Capital Employed(1)

(1)		See Frequently Used Terms on pages 93 through 95.
(2)		Earnings after income taxes including special items (2008 and 2009).
(3)		Net income attributable to ExxonMobil.
(4)		Royal Dutch Shell, BP, and Chevron values are on a consistent basis with ExxonMobil, based on public information.

COMPETITIVE ADVANTAGES:

The quality, size, and diversity of our portfolio are evident across all three of our global businesses. With operations in 47 countries, we participate in the development of all major resource types and supply key markets with high-value petroleum and petrochemical products.

ExxonMobil’s Upstream portfolio includes high-quality exploration opportunities, an industry-leading resource base, a broad range of world-class projects, and a diverse set of producing assets. The size and diversity of our resource base are unmatched and offer strategic flexibility in our investment options. Our exploration organization focuses on expanding our base of oil and gas resources by exploring for all resource types around the globe. We combine world-class technical expertise and leading research capabilities to provide a distinct competitive advantage in discovering new resources. We also actively pursue discovered but not yet developed resources.

Our success in 2012 included by-the-bit exploration discoveries in seven countries that added 2.9 billion oil-equivalent barrels to our resource base. These included discoveries in Australia, Canada, Nigeria, Papua New Guinea, Romania, Tanzania, and the United States. After adjusting for annual production, asset sales, and revisions to existing field estimates, the resource base now totals 87 billion oil-equivalent barrels. These resources represent a diverse global portfolio distributed across all geographic regions and resource types, including conventional, unconventional, and heavy oil.

In addition to our balanced resource base and project portfolio, our existing oil and gas production is diversified across all major regions, including North America, Europe, Africa, the Middle East, Asia, and Australia. In North America, we produce oil and gas in Texas, Louisiana, the Gulf of Mexico, California, the mid-continent states, Alaska, offshore eastern Canada, and onshore western Canada. We also have a significant presence in Europe, including the United Kingdom, the Norwegian North Sea, the Netherlands, and Germany. In other regions, we participate in a similarly large number of countries.

ExxonMobil’s Downstream portfolio includes a network of 32 refineries. We are one of the most geographically balanced petroleum refiners in the world, with approximately 45 percent of our refining capacity in North America, 30 percent in Europe, and the remainder in Asia Pacific and the Middle East. We have significant refining capacity in the mid-continent region of the United States and Canada, which positions us well to capture benefits from growing North American crude oil production. This geographic diversity provides flexibility in acquiring advantaged feedstocks and supplying refined products to major markets. In addition, we have the largest lubricant basestock production capacity in the world.

We sell a wide range of petroleum products in more than 120 countries, including transportation fuels such as gasoline and diesel that are sold under our global brands Exxon, Mobil, and Esso. We are a market leader in high-value synthetic lubricants, including our Mobil 1 product line, and we continue to grow the business in key markets at rates considerably faster than that of the industry. Our high-quality products, combined with a strong refining and distribution network, position us as a leading supplier around the world.

ExxonMobil’s Chemical business produces and sells a broad portfolio of products around the globe. Efficiently produced, high-volume commodity chemicals, such as many general-purpose plastics, capture upside earnings when margins are strong and provide a low cost structure for co-located specialties production. Specialty products, including high-end polymers and lubricant additives, command a market premium due to their usefulness in higher-value applications. They also provide a stable and steadily growing earnings base throughout the market cycles that characterize the chemical business.

Not unlike our Upstream and Downstream portfolios, our Chemical manufacturing operations are geographically diverse. This diversity provides us with access to a wide variety of feedstocks, and enables us to competitively supply the global market and capture regional differences in demand. For example, our U.S. Gulf Coast plants have access to ethane feedstock that is currently advantaged, allowing us to competitively supply high-demand growth markets around the world.

	ROSNEFT STRATEGIC COOPERATION AGREEMENT
	In 2012, ExxonMobil continued to progress our Strategic Cooperation Agreement with Rosneft covering 31 million acres in the Kara Sea – an area similar to the size of the entire leased area in the Gulf of Mexico – and nearly 2.7 million acres in West Siberia. We are also working with Rosneft to jointly assess and develop oil and gas in the United States and Canada.
	Right: Seismic data were collected in the Kara Sea in 2012, and exploration drilling is expected to begin in 2014.

Our geographically diverse Downstream portfolio includes a network of 32 refineries around the globe. With five refineries located in the mid-continent region of North America, including Joliet, Illinois (above), ExxonMobil is well positioned to benefit from growing crude oil production in the United States and Canada.
Chemical Segment Earnings		Chemical 2012 Prime Product Sales
Our unique Chemical portfolio captures the benefits of scale from commodity chemicals while maximizing the value of specialty chemicals. High-volume commodities capture upside earnings when industry margins are strong, while lower-volume specialties products command a market premium and provide a stable earnings base.

 

COMPETITIVE ADVANTAGES:

ExxonMobil’s disciplined approach to investing focuses on the efficient use of capital. By combining rigorous standards for project assessment with proven project development expertise, we gain advantage in our investments over the long term. This discipline is applied across our entire portfolio and includes identification of key growth opportunities and divestment of assets that no longer meet our long-term objectives. Across our worldwide operations, our return on capital employed has averaged 24 percent over the last five years, and we continue to lead competition in this important measure of long-term shareholder value.

Investment decisions in the energy industry are characterized by time horizons measured in decades. We test projects over a wide range of scenarios to ensure that all relevant risks – including financial, commercial, environmental, technical, and others – are properly identified, thoroughly evaluated, and effectively managed.

In 2012, ExxonMobil invested nearly $40 billion to bring new energy supplies and products to the market. Exploration investments are drawn from a diverse portfolio of opportunities, allowing us to effectively manage risk. From a portfolio of more than 120 Upstream projects, we expect to develop 23 billion oil-equivalent barrels across a variety of resource types and geographic regions. Our scale and diversity allow us to selectively invest in projects most likely to deliver superior financial performance and profitable volumes growth. We plan to start up 28 major Upstream projects between 2013 and 2017, which are expected to deliver approximately 1 million net oil-equivalent barrels per day of production by 2017.

Our proven project management systems ensure the efficient use of capital and lead to successful start-ups by incorporating best practices that are rigorously and consistently applied to projects around the globe. These systems employ a demanding gate review process overseen by experienced global project teams whose expertise lies in optimizing value from initial discovery through start-up. We also consider the role of technology to maximize capital efficiency. Project economics are carefully assessed, budgets are closely monitored, and reappraisals are routinely performed to further improve our performance. As a result, ExxonMobil-operated projects continue to perform at better cost and schedule certainty than those projects operated by others in which we have an interest.

Investment decisions are guided by our energy outlook, which evaluates future demands and identifies key growth markets. Our Singapore Chemical Expansion project illustrates how we identify and approach new capital commitments. The project doubled our steam-cracking capacity at the site, added unparalleled feedstock flexibility, and delivered world-class energy and cost efficiencies. Our manufacturing capacity of premium products grew significantly, including several products that ExxonMobil has never before produced in this important region.

The Singapore expansion was undertaken because petroleum and chemical demand is expected to rise rapidly in the Asia Pacific region. China’s petrochemical demand has grown by 15 percent per year from 1990 through 2010 and is expected to nearly double this decade. The Singapore plant positions ExxonMobil to participate in Asia’s rapidly growing markets. We are also expanding ultra-low sulfur diesel production capacity in Singapore, as well as lube oil blending capacity in China, to support rising demand for these high-value products in the region.

Our disciplined approach applies not only to new investments, but also to our willingness to divest assets that no longer meet our criteria for providing long-term returns. We have a long-standing practice of regularly reviewing assets to ensure they contribute to our operational and financial objectives, and we divest assets when the sale is deemed to enhance long-term shareholder value.

During 2012, we completed the sale of some of our Upstream assets, including a portion of our acreage in Angola and Norway. We also divested our Downstream and Chemical assets in Argentina, Uruguay, Paraguay, Central America, Malaysia, and Switzerland, and restructured and reduced our holdings in Japan. The transition of our U.S. retail fuel business to a more capital-efficient branded wholesaler model is also nearly complete.

Over the last 10 years, we have divested or restructured Downstream interests in 19 refineries, 6,000 miles of pipeline, 191 product terminals, 37 lube oil blend plants, and more than 22,000 retail service stations. These Downstream portfolio improvements resulted in a nearly 4-percentage-point improvement in our Downstream return on capital employed.

COMPETITIVE ADVANTAGES:

The pursuit of new technologies is vital to our long-term success. We make substantial investments in research and development to unlock new resources, improve the efficiency of our operations, and increase the value of our products. Our ongoing commitment to advancing science and technology leads to significant competitive advantage and strengthens our reputation as a partner of choice.

Our Upstream technologies provide advantages across the entire value chain, from early reservoir modeling to the drilling and completion of record-length wells, to safely producing oil and gas in some of the world’s harshest environments. Technology not only unlocks significant value in previously uneconomic resources, but it also reduces our environmental footprint and increases capital efficiency. For example, our patented full-wavefield inversion seismic technology, combined with high-performance computing capabilities, yields unparalleled high-definition subsurface images, a key advantage in identifying new resources and optimizing drilling and reservoir development plans.

Extended-reach drilling technology enables access to challenging and complex reservoirs, reducing the number of wells needed to produce oil and gas. Notably, we have drilled 26 of the world’s 30 longest-reach wells. This includes the world-record 7.7-mile-long horizontal well that we drilled in 2012 in the challenging arctic environment near Sakhalin Island in Russia.

ExxonMobil’s Subsea Technology project focuses on the development of new systems and equipment to support the development of ultra-deepwater and arctic resources. The project scope consists of more than 20 technologies for subsea processing, power generation, surveillance, and intervention that can be readily deployed. We have developed a compact separation system capable of separating oil, gas, and water at depths of up to 10,000 feet. In ultra-deep water, high external pressures prohibit subsea activities using conventional facilities. However, our advances in subsea separation are expected to provide significant safety, technical, and business benefits to ExxonMobil’s deepwater portfolio, and enable access to isolated fields that otherwise would not be developed.

Margin improvement is a strategic priority. Advantaged technologies in our Downstream and Chemical businesses enable us to reduce our raw material cost, improve catalyst performance, and optimize utilization of our facilities. We reduce raw material cost through the application of proprietary technology in the design and operation of our integrated facilities, which expands our flexibility and allows us to process the most economic feedstocks available. For example, our advanced modeling and characterization tools enable new, lower-cost feeds to be processed while obtaining greater yields of higher-value products.

Technology also supports increased production by improving reliability, removing operating constraints, and expanding market outlets. For example, our robust systems and supply chain models help us place molecules in the right market at the right time, aided by molecule management tools that enable real-time optimization of operational variables and product dispositions. In addition, advantages in catalyst technology enable “step skipping” versus traditional production routes, resulting in lower energy consumption and processing cost for the same amount of production.

An understanding of our products at the molecular level enables the development of leading-edge technologies to further improve their value to our customers. For example, we have several active programs focused on providing significant fuel economy benefits in our flagship Mobil 1 AFE products, while maintaining outstanding engine protection and reducing emissions. We also employ models that help us understand how each molecule can be best utilized to produce high-value products.

Technology breakthroughs also lead to the development of advanced catalysts to more efficiently upgrade a wide variety of feedstocks into higher-value proprietary products. For example, our metallocene catalysts are being used to manufacture premium chemical products for a wide range of applications including flexible packaging, consumer products, and lubricants. These products deliver sustainability benefits to customers that include reduced raw material use, improved performance, and greater energy efficiency.

      

      

COMPETITIVE ADVANTAGES:

We derive significant value from our globally integrated business model, which enables us to maximize the value of every molecule that we produce, leverage the advantages of our organizational structure, and optimize co-located manufacturing. Our level of integration results in structural and market advantages that are difficult for competitors to replicate.

Integration enables us to maximize the value of every molecule from wellhead to consumer. For example, more than 75 percent of our refining operations are integrated with chemical or lubes manufacturing. At these integrated sites, complex models are used to decide in real-time whether molecules should be manufactured into gasoline, diesel, jet fuel, chemicals, lubricants, or other products based on current market conditions. To take advantage of the wide variety of feedstocks available at these co-located sites, we have engineered additional flexibility into our assets to further reduce our input cost. We also leverage Integrated Business Teams with representation from various business functions to ensure optimal placement of our products.

Our integrated power generation and purchasing expertise enables the capture of additional value by increasing efficiency and reducing emissions. We are an industry leader in the application of cogeneration technology, with interest in five gigawatts of capacity across more than 100 installations. In 2012, we started up a new 220-megawatt cogeneration plant in Singapore and progressed projects that are expected to add more than 300 megawatts of additional cogeneration capacity in Canada and Europe.

Integration also maximizes value during Upstream resource evaluation and development. During the early stages of an Upstream project, our Downstream business provides technical and commercial expertise as well as world-class refining and logistics assets to enhance resource value. Commercial, technical, and supply chain support is provided to develop potential market outlets, identify and resolve challenging crude properties, and optimize logistics.

Our Kearl oil sands project demonstrates the benefits of successful integration between our Upstream and Downstream organizations. Our global supply team has a broad understanding of the marketing options for new crudes, while our refining and technology organizations have the technical knowledge to optimize the processing of Kearl production. Sharing and integrating this expertise across our supply chain adds value at every stage and enhances overall resource value and returns.

Our Upstream Gas and Power Marketing organization employs a worldwide team of commercial experts that maximize the value of our natural gas and natural gas liquids production. In the United Kingdom, for example, we maximize the throughput from our North Sea natural gas liquids extraction plants to provide feedstocks to our onshore Fife Ethylene Plant in Scotland. We have similar opportunities at our North American facilities that take advantage of increasing liquids-rich unconventional natural gas production.

Our integrated organizational structure also reduces our cost and improves our operations. For example, at each of our integrated sites, we have a shared site management and support services structure, which reduces overhead and administrative cost. We also leverage common utilities and infrastructure to reduce our energy and maintenance expense.

Common global processes and a global functional organization also capture value by enabling the rapid deployment of best practices across our global networks, resulting in improved operations. Lessons learned and expertise gained at one site are quickly transferred to other sites, resulting in continuous improvement in all aspects of our business.

      

 Upstream

The disciplined execution of ExxonMobil’s Upstream strategies, underpinned by a relentless focus on operational excellence, drives delivery of our competitive advantages and superior results.

RESULTS & HIGHLIGHTS

Proved oil and natural gas reserve additions of 1.8 billion
oil-equivalent barrels, replacing more than 100 percent
of production for the 19th consecutive year

•		Apply effective risk management, safety, and operational excellence
•		Identify and selectively capture the highest-quality resources
•		Exercise a disciplined approach to investing and cost management
•		Develop and apply high-impact technologies
•		Maximize profitability of existing oil and gas production
•		Capitalize on growing natural gas and power markets

 

		19

Demand for oil and other liquid fuels is forecast to increase by about 30 percent from 2010 to 2040. Meeting this demand will require replacing normal conventional resource decline while also increasing production from deepwater, tight oil, oil sands, and natural gas liquids. In total, approximately 113 million oil-equivalent barrels per day will be required to meet liquids demand in 2040. At the same time, global demand for natural gas is likely to increase by about 65 percent. Growth in unconventional supplies is expected to account for approximately 60 percent of that increase and approach one-third of global gas supply by 2040. Meeting growing demand presents a tremendous challenge that will require a long-term view, significant investment, and continuing innovation to develop conventional and unconventional resources.

Through the disciplined execution of our Upstream strategies, ExxonMobil is well positioned to help meet this challenge while delivering long-term value for our shareholders. We start by identifying and selectively capturing the highest-quality resources around the globe. In 2012, these efforts added nearly 1.8 million net acres to our exploration portfolio across all resource types and in some of the world’s most prospective areas.

We then apply a disciplined approach to investing and cost management. Proven project management systems incorporate best practices from around the globe to rigorously manage our project portfolio from initial discovery to start-up. In 2012, we participated in the start-up of three major liquids projects. We plan to bring 28 major projects online between 2013 and 2017, which are expected to deliver approximately 1 million net oil-equivalent barrels per day of production by 2017.

Our steadfast commitment to develop and apply high-impact technologies in areas such as subsurface imaging and well completions, allows us to find, develop, and produce new resources from some of the most challenging reservoirs and extreme environments on earth.

We apply robust operations and risk management systems to maximize the profitability of our existing oil and gas production. Over the last five years, our operated facility uptime was more than 3 percent, or more than 45 thousand net oil-equivalent barrels per day, higher than fields operated by others in which we hold an interest.

With our detailed knowledge of global energy markets we are also able to capitalize on growing natural gas and power markets. In 2012, we sold more than 15.2 billion net cubic feet per day of gas across 33 countries including participating in liquefied natural gas operations that delivered 61 million tonnes to global markets.

Overall, our Upstream business continues to apply effective risk management, safety, and operational excellence across our integrated global businesses.

UPSTREAM:

The combination of technical expertise, extensive global databases, and industry-leading research facilities allows ExxonMobil Upstream to identify, pursue, and selectively capture the highest-quality opportunities across all resource types and environments. Our ability to fully integrate and leverage these skills, combined with our worldwide experience, provides ExxonMobil a competitive advantage in the commercialization of new resources. Recognition of these capabilities creates opportunities for us as a partner of choice for other organizations.

In 2012, we captured 22 new opportunities spanning unconventional and conventional plays to build on our industry-leading resource base. At year-end 2012, our exploration acreage totaled 60 million net acres in 32 countries. Our successful efforts leveraged our North America unconventional experience to capture new unconventional acreage positions in Australia, Canada, Colombia, Germany, and Indonesia. These additions underpin future resource additions and production growth.

Australia • ExxonMobil entered into an unconventional coal bed methane (CBM) play by gaining equity in 91,000 net acres in the onshore portion of the Gippsland Basin. Efforts to evaluate and assess the natural gas potential in the coal seams is expected to commence in 2013.

Canada • We expanded our acreage position in the Montney and Nordegg plays by 32,000 net acres though participation in government land sales. These acquisitions complement our existing North America unconventional portfolio. Leveraging our extensive U.S. unconventional resource development experience will enable us to maximize value from these assets.

Colombia • ExxonMobil established a significant position in the emerging unconventional tight liquids play in the Middle Magdalena Basin area through entry into four blocks covering 404,000 net acres and one technical evaluation agreement covering an additional 160,000 net acres. Exploration drilling and seismic data acquisition programs started in 2012 and will continue into 2013.

Germany • Three licenses totaling 68,000 net acres were awarded to ExxonMobil in 2012, expanding our acreage position in unconventional tight liquids.

Indonesia • We increased our exploration acreage position in the Barito coal bed methane basin by an additional 227,000 net acres.

Papua New Guinea • We expanded our exploration position in the Papuan Highlands by adding 544,000 net acres in PPL 260 and PPL 277 adjacent to our Papua New Guinea Liquefied Natural Gas (LNG) project.

U.S. Offshore • We expanded our position in the Gulf of Mexico by a combined 395,000 net acres through participation in GOM Lease Sale 218, GOM Lease Sale 216/222, and two farm-ins.

U.S. Onshore • ExxonMobil acquired 192,000 net acres in the Bakken Shale play, increasing our position by nearly 50 percent. We further expanded our industry-leading position in the liquids-rich Woodford Ardmore Shale in southern Oklahoma to more than 270,000 net acres through acquisition and leasing. We also increased our acreage position to nearly 90,000 net acres in the emerging Utica Shale play.

In 2012, we signed several agreements which, when finalized, will underpin future resource additions and production growth.

Canada • ExxonMobil entered into an agreement with Celtic Exploration Ltd. to acquire 545,000 net acres in the liquids-rich Montney play, 104,000 net acres in the Duvernay play, and additional acreage in other areas of Alberta. Imperial Oil will acquire a 50-percent working interest in this acreage.

Russia • ExxonMobil is working with Rosneft to evaluate the exploration potential of the Kara Sea, Black Sea, and West Siberia. In West Siberia, a Pilot Development Agreement was signed that will lead to a joint venture to execute a pilot program and develop potential commercial production of tight oil reserves at the Achimov and Bazhenov formations with equity interests of 51 percent Rosneft and 49 percent ExxonMobil. Work will be carried out on Rosneft’s 23 license blocks covering 2.7 million acres.

South Africa • ExxonMobil signed an agreement to acquire a 75-percent interest in the Tugela South Exploration Right (2.8 million acres). Under the agreement, we also have the option to acquire a 75-percent interest in future exploration rights in three offshore areas covering 12 million net acres. In addition, ExxonMobil executed a technical cooperation permit with the South African government to study the hydrocarbon potential of the Deepwater Durban Basin, covering approximately 12.3 million acres.

Ukraine • In August 2012, an ExxonMobil-led consortium won the tender for the Skifska offshore block in the Black Sea totaling 1.65 million net acres (ExxonMobil interest, 40 percent). We are working with our co-venturers and the Ukrainian government to finalize the Production Sharing Agreement.

In 2012, we continued to build our diverse global portfolio of resources and reserves by adding 4 billion oil-equivalent barrels. After adjusting for production, asset sales, and revisions to existing fields, the resource base totals more than 87 billion oil-equivalent barrels. Proved reserves comprise approximately 29 percent of the resource base, or 25.2 billion oil-equivalent barrels.
The addition of an average of 4.3 billion oil-equivalent barrels to our resource base per year over the last decade demonstrates the success of our global strategy to identify, evaluate, pursue, and capture high-quality opportunities. Today, ExxonMobil holds the largest global resource base among international oil companies. The size and diversity of our resource base afford further advantage by supporting global risk management and offering unequaled investment flexibility.

We continue to increase and expand the quality of our resources through successful by-the-bit drilling, capture of undeveloped resources, strategic acquisitions, and increased recovery from existing fields. In 2012, resources were added in Australia, Canada, Nigeria, Papua New Guinea, Romania, Tanzania, and the United States.

Our by-the-bit drilling exploration program added 2.9 billion oil-equivalent barrels in 2012, with additions from multiple resource types around the world. Additions from exploration drilling averaged approximately 2.1 billion oil-equivalent barrels per year over the last decade.

Our resource base is assessed annually to include new discoveries and changes in estimates for existing resources. Changes may result from additional drilling, revisions to recovery estimates, application of new technologies, or ongoing and rigorous geoscience and engineering evaluations. Resource base volumes are adjusted downward for volumes produced during the year and resources associated with asset divestments. Adjustments may also occur with changes to fiscal regime, equity, or depletion plans.

The largest components of ExxonMobil’s resource base remain conventional, unconventional gas and oil, and heavy oil/oil sands, which comprise 70 percent of the total. LNG and deepwater account for about 14 percent of the total resource base. The remaining 16 percent is made up of arctic and acid/sour gas resources.

ExxonMobil’s resource base includes 25.2 billion oil-equivalent barrels of proved oil and gas reserves, equating to 16 years of reserves life at current production rates. These reserves represent a diverse global portfolio distributed across all geographic regions and resource types, with a higher proportion of liquids.

Resource Base Distribution(1)		Resource Base Distribution(1)
(percent, oil-equivalent barrels) By Region		(percent, oil-equivalent barrels) By Resource Type

(1) See Frequently Used Terms on pages 93 through 95.

Revisions to proved reserves have averaged about 0.4 billion oil-equivalent barrels per year over the last five years, driven by effective reservoir management and the application of new technologies. We have more than replaced our production for 19 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.

Resource Additions/Acquisitions(1)		Proved Reserves Distribution(1)
(percent, oil-equivalent barrels added, 2008-2012) By Resource Type		(percent, oil-equivalent barrels) By Region

(1) See Frequently Used Terms on pages 93 through 95.
(2) Includes asset sales.

UPSTREAM:

ExxonMobil’s commitment to research and development is a key contributor to our long-term success. We develop and apply innovative solutions to increasingly complex technical challenges. Our breakthrough technologies enable the discovery of new resources, access to harsh environments, and the economic development of challenging reservoirs never before thought possible.

 

application of gravity-based structures and developing new concepts for drilling, offshore loading, and subsea production. Technological advancements in these areas are expected to address many of the unique challenges associated with oil and gas development in arctic environments. Elements of these programs are being worked cooperatively with Rosneft as part of our effort to increase knowledge of the Kara Sea arctic environment.

ExxonMobil’s advanced technologies in the areas of reservoir characterization and drilling and completions enable us to find and develop challenging reservoirs.

Accurately measuring and characterizing rock properties in unconventional reservoirs is essential to designing effective and economic developments. The properties of the ultra-low permeability rocks found in unconventional reservoirs are difficult to measure. ExxonMobil’s expertise in this area is enabled by our cutting-edge laboratory and analytical capability and our unmatched dataset of unconventional assets. We are leveraging this expertise to develop new standards for characterizing rock properties in low-permeability reservoirs, allowing us to better predict their production behavior over time.

ExxonMobil’s new patent-pending acoustic fluid inclusion volatile technology enables the evaluation of production intervals within tight liquid and shale gas systems. The acoustic signals generated during the crushing of rock samples are correlated to specific rock properties. We use this innovative technology to distinguish brittle, silica-rich shales, which are more productive, from softer, clay-rich shales. This information allows us to optimize our design and development plans to maximize profitable recovery.

We are also leveraging our drilling and completions technologies to increase recovery from challenged reservoirs. Combining our industry-leading extended-reach drilling capability with our proprietary stimulation technology has significantly enhanced profitable recovery. By optimizing how and where stimulation fluid interacts with rock, we are able to sustain production rates along the length of the wellbore, delay
compression investments, and increase recovery. Additionally, our proprietary MazeFlo technology enhances economic recovery from reservoirs with sand control issues. The self-healing MazeFlo sand screen increases production by improving sand control reliability. This new technology is currently being applied in Nigeria where we anticipate improved recovery and significant cost savings through extended well life and reduced downtime.
		Our proprietary MazeFlo technology, which is incorporated into our sand screen designs, is installed across a well’s producing interval. This technology extends well life and reduces downtime, resulting in increased recovery and significant cost savings.

UPSTREAM:

Our disciplined investment approach combines rigorous project evaluation and tactical development with technical and commercial expertise. We deploy this approach across the project life cycle, from initial resource capture and project implementation to ongoing process and operational improvements. Utilizing proven project management systems, experienced global teams rigorously manage our portfolio from initial discovery to start-up, resulting in superior cost and schedule performance. We have a singular focus: to drive superior investment returns for the long term.

Usan • (ExxonMobil interest, 30 percent) Usan started up in
February 2012 utilizing a floating production, storage, and offloading (FPSO) vessel located approximately 60 miles offshore Nigeria in Block OML138. The facility has the capacity to produce 180 thousand barrels per day.

Kizomba Satellites Phase 1 • (ExxonMobil interest, 40 percent) Kizomba Satellites Phase 1 started up in May 2012 as a subsea tieback to existing FPSO facilities in Angola Block 15. Development drilling is expected to continue until 2014 toward a production target of 100 thousand barrels per day.

Nigeria Satellite Field Development Phase 1 • (ExxonMobil interest, 40 percent) Nigeria Satellite Field Development Phase 1 started up in October 2012. The project will have a peak capacity of 70 thousand barrels per day. The three wellhead platforms are the first offshore structures of this scale to be designed, procured, and constructed in Nigeria.

Kearl Initial Development • (combined ExxonMobil and Imperial Oil interest, 100 percent) Kearl Initial Development commenced commissioning activities in late 2012, with first oil anticipated in early 2013. 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. The Kearl Expansion project and debottlenecking have the potential to increase total Kearl production up to 345 thousand barrels per day. Kearl represents the first mining operation to employ a new proprietary paraffinic froth treatment technology, which produces a salable crude oil without the need for an upgrader. As a result, Kearl’s life cycle greenhouse gas emissions will be similar to many other crude oils processed in the United States.

Project success is built from the ground up and begins by incorporating our “Building the Producing Organization” philosophy into each new venture. This philosophy provides a framework for engaging the full operations team from the project’s outset. Team members provide input on design, engineering, and construction, and work to establish management systems and training of personnel, including nationals. The operations team’s early and ongoing involvement builds knowledge of the project over the course of its development, and results in high standards for completion. It also provides start-up efficiencies and operability improvements that further drive long-term shareholder value.

Projects by Geographic Region (percent, number of projects)		Projects by Resource Type (percent, oil-equivalent barrels)		Projects by Hydrocarbon Type (percent, oil-equivalent barrels)

 

 

 

UPSTREAM:

ExxonMobil has an interest in exploration and production acreage in 36 countries and production operations
in 23 countries.

With a focus on technological improvements,
operational efficiency,
and high-quality drilling programs,
we 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
plays, seven of which
are estimated to
contain recoverable
reserves of greater
than 1 billion
oil-equivalent
barrels. Future developments
are also planned from
ExxonMobil’s
extensive deepwater Gulf of Mexico acreage position.

2012 average net production
in the Gulf of Mexico
was 52 thousand barrels
of liquids per day and
208 million cubic feet of gas.

Deepwater • In the deepwater Gulf of Mexico, we
operate the Hoover
platform that is located
in more than 4,800 feet of water
and produces oil and gas
from the Hoover field and
several subsea tiebacks. In addition, we are a partner in six deepwater fields,
including the co-venturer-operated Thunder Horse field (ExxonMobil interest, 25 percent) where active drilling is ongoing.

Activity also continues in the Keathley Canyon (KC) area. We are developing the 2011 Hadrian-5 discovery under a unit agreement as part of the co-venturer-operated Lucius development (initial ExxonMobil interest, 15 percent). The Hadrian South project (ExxonMobil interest, 47 percent), which is situated in KC-963 and KC-964, is being developed as a subsea tieback to the Lucius platform. Both projects are expected to start up in 2014.

We continue to progress engineering for development of the Hadrian North oil discovery (ExxonMobil interest, 50 percent), situated on blocks KC-918 and KC-919. The Hadrian-6 and Hadrian-7 appraisal wells were drilled in the second half of 2012.

      

      

A third appraisal well is planned for early 2013 to better define the Hadrian North resource. Activity continues on the Julia Phase 1 project (ExxonMobil interest, 50 percent) in the Walker Ridge area, which is a subsea tieback to the co-venturer-operated Jack-St. Malo host facility. Engineering, contracting, and technology qualification activities are progressing, with full funding planned in 2013.

ExxonMobil also began participating in early engineering and procurement activities for development of the co-venturer-operated Heidelberg discovery located in a five-block unit in Green Canyon (ExxonMobil interest, 9 percent).

Our substantial exploration portfolio of 1.7 million net acres in the deepwater Gulf of Mexico continues to expand with investments in advanced seismic data to further enhance understanding of the subsurface. ExxonMobil was the high bidder on 66 deepwater blocks in GOM Lease Sale 218 and GOM Lease Sale 216/222. We also expanded our acreage position through farm-ins at the Thorn (ExxonMobil interest, 35 percent) and Phobos (ExxonMobil interest, 20 percent) prospects.

Conventional • The Mobile Bay development offshore Alabama contributed net production of 136 million cubic feet of gas per day during 2012. We are now realizing the cost efficiency and environmental benefits associated with the consolidation of our sour gas plants in late 2010.

LNG • Golden Pass Products, LLC, a partnership of ExxonMobil and Qatar Petroleum International, initiated federal permitting to add up to 15.6 million tonnes per annum of proposed export capabilities to the existing Golden Pass LNG terminal, a liquefied natural gas (LNG) import terminal at Sabine Pass, Texas. This project affords this world-class LNG terminal the opportunity to import or export natural gas in response to market conditions.

ExxonMobil is a leading producer in Louisiana and Texas with a strong position in multiple unconventional gas plays and the Permian Basin. In 2012, onshore net production in Texas and Louisiana averaged 101 thousand barrels of liquids per day and 2 billion cubic feet of gas per day.

Conventional • In the Permian Basin, we completed more than 100 wells across multiple legacy fields, primarily Goldsmith, Russell Clearfork, and Nash. We are evaluating the results of the Means Residual Oil Zone project that started up in late 2011 and are developing other enhanced oil recovery projects in East Texas. ExxonMobil also started up the Hawkins Nitrogen Recovery Unit project in 2012. 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 approximately 240,000 net acres in the Haynesville/Bossier Shale of East Texas and Louisiana where we continued to realize the benefits of our drilling and completion efficiency efforts. We also continued the assessment of the overlying Bossier Shale reservoir that is present across much of the southern area of the Haynesville play.

      

Upstream: Worldwide Upstream Operations, continued

In the Barnett Shale play in North Texas, we completed more than 170 wells in 2012 across a leasehold of approximately 230,000 net acres spanning 24 counties. In the Freestone tight gas play, ExxonMobil holds approximately 320,000 net acres. We brought 95 wells online in 2012, and continue to progress infrastructure projects designed to handle high-volume horizontal completions. In the South Texas Eagle Ford Shale play, ExxonMobil drilled 11 wells in 2012. In the Permian Basin, we continued to evaluate multiple unconventional reservoirs, including the Bone Springs, Avalon, and Wolfcamp tight oil plays.

ExxonMobil produces oil and gas throughout the mid-continent states, including Wyoming, Utah, North Dakota, Montana, Colorado, Kansas, Oklahoma, Arkansas, and New Mexico, as well as the Appalachian states of Pennsylvania and West Virginia. Average net production from these areas in 2012 was 66 thousand barrels of liquids per day and more than 1.5 billion cubic feet of gas per day.

production. Additionally, this acreage is located close to our current development areas, generating further efficiencies. The Woodford Ardmore Shale play in southern Oklahoma was our most active unconventional drilling program in 2012, with 12 operated rigs delineating and developing more than 270,000 net acres of leasehold. In addition, infrastructure projects are advancing to optimize the liquids-rich production from this area. Construction was completed on a 117-mile natural gas gathering pipeline from our operations in southern Oklahoma to processing facilities in North Texas.

In the Fayetteville Shale, pad drilling, optimized well spacing, and improved drilling processes are increasing efficiencies as development continues on our 505,000 net acre leasehold. In 2012, we completed a pilot to assess the potential to reduce completion cost and increase well productivity and recovery utilizing ExxonMobil’s Just-In-Time Perforating (JITP) fracture stimulation process.

ExxonMobil also holds a material acreage position in the Marcellus Shale (approximately 625,000 net acres) and the promising Utica Shale in West Virginia and Ohio (approximately 90,000 net acres). We drilled our first wells in the Utica Shale in 2012, with completions planned in early 2013.

In Colorado, the Piceance development (ExxonMobil interest, 100 percent) contributed net production of approximately 100 million cubic feet of gas per day in 2012. ExxonMobil has approximately 300,000 net acres in the Piceance Basin.

      

      

Net production from fields both onshore and offshore California averaged 88 thousand barrels of liquids per day and 19 million cubic feet of gas per day during 2012.

The Santa Ynez Unit (SYU) 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 2012, development drilling continued at the SYU Heritage platform. Onshore California, we are finalizing plans to commence further development drilling in 2013. ExxonMobil also has a 48-percent equity share in Aera Energy LLC’s operations, comprising eight fields and approximately 11,000 wells that produce a mixture of heavy and conventional oil with associated natural gas.

Average net production in Alaska was 110 thousand barrels of liquids per day in 2012. ExxonMobil is the largest holder of discovered natural gas resources on the North Slope of Alaska. In early 2012, ExxonMobil, along with the other owners, finalized a settlement agreement with the State of Alaska regarding the Point Thomson Unit. The agreement commits the parties to the initial development phase of the Point Thomson project. Additionally, the major producers and TransCanada commenced concept selection work to assess LNG exports from southcentral Alaska as an alternative to a natural gas pipeline to Alberta.

ExxonMobil is 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.

(ExxonMobil interest, 51 percent; Imperial Oil interest, 9 percent) in Nova Scotia comprises five producing fields. Net production in 2012 averaged 92 million cubic feet of gas per day and 5 thousand barrels of associated natural gas liquids per day.

The Hebron project (ExxonMobil interest, 36 percent) is an ExxonMobil-operated oil development located in 300 feet of water offshore Newfoundland. The planned gravity-based structure with topsides facilities and drill rig will have a capacity of 150 thousand barrels per day. In 2012, the Hebron project development plan was approved by the Canada-Newfoundland and Labrador Offshore Petroleum Board, and the project was fully funded. Additionally, site preparation activities were completed for construction of the concrete gravity-based structure and contracts were awarded for construction of topsides modules. Start-up is expected around the end of 2017.

      

Upstream: Worldwide Upstream Operations, continued

ExxonMobil and Imperial Oil continue to progress the assessment of blocks EL476 and EL477 (formerly EL446 and EL449) in the arctic Beaufort Sea, covering 500,000 net acres (combined ExxonMobil and Imperial Oil interest, 50 percent). In 2012, license extensions were granted. Interpretation of 3D seismic data continues and planning for the first exploration well is progressing.

In 2012, the Cold Lake heavy oil field in Alberta (Imperial Oil interest, 100 percent) achieved production of 123 thousand net barrels of oil per day. Cold Lake is the largest thermal in situ heavy oil project in the world. It has more than 4,000 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. Since the inception of the Cold Lake project, continuous improvements and advances in technology have allowed us to more than double the expected recovery from the initial commercial development area. Engineering is complete and drilling and construction work have commenced on the Nabiye project, the next expansion phase of the Cold Lake development, which will add an additional capacity of 50 thousand barrels of bitumen per day.

The Syncrude oil sands mining operation (Imperial Oil interest, 25 percent) produced synthetic crude averaging 69 thousand net barrels per day in 2012. We are progressing several projects to sustain production and continue to evaluate future developments including Mildred Lake Extension and Aurora South Phases 1 and 2.

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. Commissioning of the initial development commenced in late 2012 and is expected to deliver approximately 110 thousand barrels of bitumen per day. Fabrication and construction is well under way on the expansion project, which is expected to produce an additional 110 thousand barrels of bitumen per day. Future debottlenecking of both the initial development and expansion project is expected to increase total production to 345 thousand barrels of bitumen per day.

In 2012, we also continued to evaluate oil sands acreage in the Athabasca region on both in situ and mining leases including Aspen, Corner, Grand Rapids, and Firebag. We acquired an additional 2,880 net acres of high-quality oil sands leasehold in 2012 through Imperial Oil to support future mining developments. ExxonMobil is continually leveraging our extensive acreage position in Canada to maximize value through selective swaps, farm-ins, and divestments.

The Mackenzie Gas project received regulatory approvals from the Canadian government in 2011. Once sanctioned, the project will develop three fields containing approximately 6 trillion cubic feet of natural gas and will deliver natural gas to North American markets through a 740-mile pipeline system across the Mackenzie Valley. ExxonMobil and Imperial Oil hold interests in two of the three fields.

In the Horn River Basin in northeast British Columbia (combined ExxonMobil and Imperial Oil interest, 100 percent) we currently hold approximately 340,000 net acres and are one of the largest landholders in the basin. Evaluation of our acreage position has progressed with the start-up of a pilot project consisting of eight horizontal production wells and associated facilities. Production started in August 2012 from the 30-million-cubic-feet-per-day capacity facility.

      

      

In addition, RN Cardium Oil Inc., an independent Rosneft subsidiary, acquired 30 percent of ExxonMobil’s stake in the Cardium acreage in the Harmattan area. ExxonMobil and Imperial Oil also acquired a 100-percent interest in an additional 32,000 net acres in Alberta across a variety of plays.

In October 2012, ExxonMobil entered into an agreement to acquire Celtic Exploration Ltd. Under the terms of the agreement, ExxonMobil Canada will acquire 545,000 net acres in the liquids-rich Montney play, 104,000 net acres in the Duvernay play, and additional acreage in other areas of Alberta. Leveraging our extensive U.S. unconventional resource development experience will enable us to maximize value of these resources. Imperial Oil will acquire a 50-percent interest in these plays.

We also acquired rights to explore four blocks for unconventional tight liquids in the emerging La Luna play in the Middle Magdalena Basin area totaling 404,000 net acres. Two blocks were acquired through farm-in agreements (VMM-2 and VMM-37), (ExxonMobil interest, 70 percent) and two blocks (COR-62 and VMM-29) were awarded to ExxonMobil and

      

Upstream: Worldwide Upstream Operations, continued

ExxonMobil is among the largest oil and gas producers in Norway,
with average net production of 177 thousand barrels of liquids per day and
605 million cubic feet of gas per day in 2012. 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 approximately 110 miles
west of Stavanger.

Ringhorne has produced more than 240 million oil-equivalent
barrels since coming onstream in 2003, with Balder yielding
more than 180 million oil-equivalent barrels since its start-up in
1999. In 2012, production averaged 43 thousand net
oil-equivalent barrels per day for Balder and Ringhorne
combined.

We continued drilling operations from the Ringhorne
platform in 2012, following a 4D seismic program
in 2010. During the year, we also conducted an
additional seismic survey in the Balder/Ringhorne
area to support continued field development.
A drilling program for the Balder field is
planned to begin in 2013.

ExxonMobil is also a partner in more than 20
co-venturer-operated fields. There are active
drilling programs in several core areas,
with approximately 25 new wells drilled per year,
as well as field extensions designed to fill
available facility capacity as mature
fields decline.

In 2012, ExxonMobil also completed an equity
swap with Total SA. The transaction increased
our equity in the producing Snorre, Statfjord East,
and PL089 (Tordis/Vigdis) licenses in exchange
for our equity interest in the Dagny license,

      

Oseberg field, and the Oseberg transportation system. The exchange strengthens our equity in these assets and positions us, with our advanced technologies and operating expertise, to work with the operator and partners to maximize economic resource recovery.

Progress continues on new subsea technology with the execution of the Aasgard Subsea Compression (ASC) project (ExxonMobil interest, 13.5 percent) and advancement of a subsea compression pilot at Ormen Lange. The ASC project will help to maximize recovery from the Aasgard and Mikkel fields. This project is in the execution phase and represents an industry first in the application of subsea compression.

ExxonMobil holds three exploration licenses covering 766,000 net acres over Rån Ridge (ExxonMobil interest, 50 percent) and Ygg High (ExxonMobil interest, 30 percent) in the deepwater outer Vøring Basin and Møre Vest (ExxonMobil interest, 35 percent) in the Møre Basin. A 3D seismic survey was acquired over the Ygg High acreage in the third quarter of 2012 and is currently being processed. The primary exploration target is located beneath thick basalt layers that will require the application of specialized imaging technology to identify potential future drilling opportunities.

In October 2012, we sold our 15-percent interest in the Aasta Hansteen (formerly Luva) development.

ExxonMobil has significant equity participation in more than 40 producing fields in the North Sea. In 2012, the ExxonMobil net production from these fields yielded 20 thousand barrels of liquids per day and 306 million cubic feet of gas per day, primarily from a joint venture operated by Shell.

Also in 2012, the Fram offshore development project (ExxonMobil interest, 68 percent) was fully funded and the field development plan was approved. Drilling commenced in July 2012.

The South Hook LNG regasification terminal (ExxonMobil interest, 24 percent) located in Milford Haven, Wales, delivers gas to the United Kingdom’s natural gas grid. In 2012, 67 LNG cargoes were delivered, providing more than 7 million tonnes of LNG.

		The South Hook LNG terminal in the United Kingdom is a key asset in our global LNG portfolio.

ExxonMobil is Germany’s largest natural gas producer, with production from ExxonMobil-operated fields accounting for approximately 70 percent of all natural gas produced in the country. In 2012, these fields generated an average net production of 468 million cubic feet per day. During the year, we also reduced our operational footprint through a series of infrastructure rationalization and upgrade projects.

Our subsidiaries in Germany hold nine exploration licenses in Lower Saxony, Hamburg, and North Rhine Westphalia. These licenses cover 2.8 million net acres and include potential shale gas, tight liquids, and coal bed methane exploration plays. Future exploration activities await the outcome of ongoing discussions with regulators and communities on the subject of hydraulic fracturing.

      

Upstream: Worldwide Upstream Operations, continued

Nederlandse Aardolie Maatschappij (NAM), a 50-percent ExxonMobil equity company with Shell as the operator, is the largest natural gas producer in the Netherlands. Gas is produced from more than 100 fields located both onshore and offshore. Daily net production in the Netherlands averaged 1.8 billion cubic feet of gas in 2012. The majority of this production comes from the Groningen field (ExxonMobil interest, 30 percent), which is Europe’s largest natural gas field. In 2012, NAM commenced the Underground Storage Expansion project at Norg, which will help to sustain peak Groningen gas deliveries.

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 only fixed offshore LNG storage and regasification terminal. In 2012, 70 LNG cargoes were delivered, providing 4.3 million tonnes of LNG to the Italian natural gas grid.

Faroe Islands • ExxonMobil holds 535,000 net acres through a 49-percent interest in license L006 and a 50-percent interest in licenses L009 and L011. The three licenses are operated by Statoil. Drilling of the Brugdan-2 wildcat well on license L006 began in June 2012 and was subsequently suspended due to the onset of winter weather.

Greenland • In 2012, ExxonMobil completed the geological evaluation of Blocks 4 and 6 in the Disko West area, offshore Greenland.

Ireland • ExxonMobil has interests in two Frontier Exploration Licenses (FEL): Dunquin FEL 3/04 (ExxonMobil interest, 27.5 percent); and Cuchulain FEL 1/99 (ExxonMobil interest, 36 percent). These licenses cover approximately 225,000 net acres in the Porcupine Basin, approximately 125 miles off the southwest coast of Ireland.

Poland • Our interest in Poland includes four Podlasie Basin licenses (ExxonMobil interest, 100 percent) and two Lublin Basin licenses (ExxonMobil interest, 51 percent). In 2012, we commenced the process to withdraw from our Polish licenses, having met all commitments.

Romania • ExxonMobil has a 50-percent working interest covering 932,000 net acres in the Neptun Deep block in the Black Sea. In early 2012, the ExxonMobil-operated Domino-1 wildcat was drilled approximately 110 miles offshore and encountered gas. New 3D seismic data acquisition commenced in late 2012 to further assess the Domino discovery potential and the remainder of the Neptun Deep block. Appraisal activities are progressing with additional drilling anticipated to commence in 2013.

Turkey • ExxonMobil interests in the Turkish Black Sea include the Kastamonu sub-block of license 3921 (ExxonMobil interest, 50 percent), the Samsun sub-block of license 3922 (ExxonMobil interest, 50 percent) and the Sinop, Ayancik, and Carsamba sub-blocks in the Petrobras-operated license 3922 (each with ExxonMobil interest, 25 percent). In 2012, we commenced the process to withdraw from our Turkish licenses having met all commitments.

      

      

Additional Block 15 development focuses on the Kizomba Satellites projects. Kizomba Satellites Phase 1 successfully started up in May 2012. The Kizomba Satellites Phase 2 project, which includes subsea tiebacks to the Kizomba B and Mondo floating production, storage, and offloading (FPSO) vessels, was fully funded. The Phase 2 project is expected to produce nearly 190 million barrels of oil, and production is anticipated to start in 2015. Through collaborative development efforts, we continue to utilize the local workforce to enhance Angolan economic development and competitiveness.

Block 17 • ExxonMobil has a 20-percent interest in Block 17. Through year-end 2012, 15 discoveries have been made on the block with a gross recoverable resource potential of approximately 5 billion oil-equivalent barrels. During 2012, production averaged more than 600 thousand barrels of oil per day from the Girassol, Dalia, Rosa, and Pazflor projects.

The Pazflor project (ExxonMobil interest, 20 percent) started up in August 2011. Pazflor is located 100 miles offshore in 2,600 feet of water and utilizes an FPSO vessel to produce up to 220 thousand barrels of oil per day. Project execution activities continued for the Cravo-Lirio-Orquidea-Violeta (CLOV) project, which was sanctioned in 2010. CLOV is located in

      

      

Upstream: Worldwide Upstream Operations, continued

Block 31 • The sale of our 25-percent interest in Block 31 to Sonangol E&P closed in June 2012.

Block 32 • Development planning activities continue for Block 32 (ExxonMobil interest, 15 percent). Through year-end 2012, 12 discoveries have been announced with a total gross resource of approximately 1.4 billion oil-equivalent barrels. The first FPSO vessel development planned for Block 32 is the Kaombo Split Hub project in the southeastern section of the block, with estimated recovery of approximately 560 million barrels of oil. The water depths on this block range from 4,700 to 5,600 feet. An appraisal well was drilled in 2012 to further define the resource.

ExxonMobil continues to develop our interest in offshore Nigeria, both in shallow and deepwater acreage. We operate a shallow-water joint venture with the Nigerian National Petroleum Corporation (NNPC) offshore southeastern Nigeria (ExxonMobil interest, 40 percent for crude and condensate; 51 percent for natural gas liquids) and the deepwater Erha and Erha North fields. ExxonMobil also produces from co-venturer-operated fields. Development drilling and project activities using Nigeria’s expanding capabilities are under way to further develop our interests. In 2012, net production in Nigeria averaged 293 thousand barrels of liquids per day.

Erha/Erha North • The Erha development (ExxonMobil interest, 56 percent) is located 60 miles offshore in 3,900 feet of water. The development consists of more than 30 subsea wells tied back to an 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. Start-up is targeted for 2016.

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 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.

Bonga North • The Bonga North development (ExxonMobil interest, 20 percent) is planned as a new-build FPSO vessel using a “design one, build multiple” approach with Bonga Southwest. It is anticipated that the project will develop more than 350 million barrels of oil.

      

      

Usan • First production from the Usan project (ExxonMobil interest, 30 percent) was achieved in February 2012. Usan is located 60 miles offshore Nigeria in 2,500 feet of water. Full development 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. Drilling to increase capacity continues and evaluation of concepts to develop future phases is under way.

Nigeria Shelf – Joint Venture

ExxonMobil’s portfolio on the Nigerian shelf encompasses 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 data acquisition and exploration activities continue in an effort to identify new opportunities within the joint venture.

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 achieved first oil in October 2012 with the installation of three new platforms. These additional offshore facilities will allow drilling in undeveloped areas of the joint venture and provide pipeline connections to existing infrastructure. Peak production from Phase 1 is anticipated to reach 70 thousand barrels of liquids per day and recover more than 120 million barrels of oil and natural gas liquids. Project activities are progressing on Phase 2 of the Satellite Field Development.

Natural Gas Liquids • Production of natural gas liquids occurs from the Oso Natural Gas Liquids project and the East Area Natural Gas Liquids II project (ExxonMobil interest, 51 percent). Production from these two projects averaged 35 thousand barrels per day in 2012. The projects are expected to recover approximately 400 million barrels of natural gas liquids. In

      

      

Upstream: Worldwide Upstream Operations, continued

ExxonMobil operates the Zafiro field in Equatorial Guinea (ExxonMobil interest, 71 percent) in water depths between 400 and 2,800 feet. The Zafiro field has produced more than 900 million barrels in its 16 years of production. In 2012, net production averaged 38 thousand barrels of oil per day. A successful multiyear drilling program concluded in 2011 with the addition of more than 25 million barrels of reserves.

ExxonMobil is Chad’s leading oil producer (ExxonMobil interest, 40 percent) with average net production of 36 thousand barrels of oil per day in 2012. An active two-rig development drilling program continued in 2012, focused on the Kome, Bolobo, and Miandoum fields.

ExxonMobil holds a 35-percent working interest in deepwater Block 2 in Tanzania. A 3D seismic survey was completed in 2010 and identified multiple deepwater drilling prospects. Three successful exploration wells were drilled in 2012 (Zafarani-1x, Lavani-1, and Lavani-2). These wells discovered gas in multiple reservoir intervals with an estimated recoverable resource range of 7 to 9 trillion gross cubic feet of natural gas. Additional drilling and 3D seismic data acquisition are planned to further assess the potential of the block.

Republic of Congo • Through year-end 2012, five discoveries were announced in the Mer Tres Profonde Sud block (ExxonMobil interest, 30 percent) with a total resource of approximately 400 million gross oil-equivalent barrels. Additional exploration activity is planned for 2013.

Libya • We relinquished our interest in Contract Area 44 in November 2010. ExxonMobil has been under force majeure since March 2011 in Contract Areas 20 and 21.

Madagascar • ExxonMobil affiliates have three Production Sharing Contracts in the deepwater Majunga Basin offshore northwestern Madagascar. After a period of suspension, ExxonMobil is pursuing ratification of extensions to the contracts. We continue to evaluate the basin’s potential.

South Africa • ExxonMobil entered into a participation agreement with Impact Africa Limited for a 75-percent interest in the Tugela South Exploration Right (2.8 million acres) and a 75-percent interest in potential exploration rights for additional blocks offshore South Africa. Additionally, ExxonMobil was granted a Technical Cooperation Permit that provides exclusive rights to evaluate the resource potential of the Deepwater Durban

      

      

ASIA

and the Barzan gas project. LNG production from ExxonMobil-interest trains in Qatar was 61 million tonnes in 2012.

Al Khaleej Gas • The Al Khaleej Gas (AKG) Phase 1 and 2 project facilities are helping to meet growing domestic demand in Qatar. The combined capacity of these facilities is 2 billion cubic feet per day.

Barzan • The initial phase of the Barzan project, scheduled to start up in 2014, will supply up to 1.4 billion cubic feet per day of natural gas, primarily to meet the demand driven by Qatar’s rapidly growing infrastructure and industry requirements. Onshore and offshore construction activities are on schedule, and a large portion of the development drilling is complete.

      

      

Upstream: Worldwide Upstream Operations, continued

RasGas • RasGas is a joint venture between Qatar Petroleum and ExxonMobil, with 70-percent and 30-percent interests, respectively. RasGas operates a total of seven LNG trains with capacities ranging from 3.3 million to 7.8 million tonnes per year with a combined production capacity of 36 million tonnes per year. LNG from the seven trains is sold predominantly to the Asian and European markets. RasGas also employs a fleet of LNG carriers including Q-Flex and Q-Max vessels. In addition to LNG, RasGas also produces substantial volumes of associated products including condensate, liquefied petroleum gas, helium, and sulfur.

Common Facilities • Qatargas and RasGas also participate in common facilities for the storage and loading of LNG, condensate, liquefied petroleum gas, and sulfur on behalf of the Ras Laffan Industrial City joint venture companies. Sharing common facilities enables all participants to benefit from economies of scale.

ExxonMobil signed agreements with the South Oil Company 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). Located in one of Iraq’s most prolific producing areas, West Qurna I field redevelopment and expansion will entail extensive infill drilling, reservoir pressure support, development of undeveloped reservoirs, extensive new production facilities, and associated support infrastructure.

In 2012, we continued with redevelopment activities and the finalization of long-term development plans. Seismic data acquisition and water injection activities are under way.

      

      

At year-end 2012, production from West Qurna I exceeded 460 thousand barrels per day, representing an increase of nearly 90 percent since the contract award.

In October 2011, ExxonMobil signed six Production Sharing Contracts (PSC) (ExxonMobil interest, 100 percent) covering 848,000 acres in the Kurdistan region of Iraq. In 2012, we continued to meet our obligations under the PSCs, including planning activities for seismic data acquisition and drilling.

ExxonMobil operates the Sakhalin-1 project (ExxonMobil interest, 30 percent), which comprises the Chayvo, Odoptu, and Arkutun-Dagi fields. The Sakhalin-1 project, which is being developed in phases, represents one of the largest foreign investments in Russia.

      

Upstream: Worldwide Upstream Operations, continued

The Azeri-Chirag-Gunashli (ACG) megafield (ExxonMobil interest, 8 percent) has produced 2.1 billion barrels of oil since its 1997 start-up. In 2012, ACG production averaged 664 thousand barrels of oil per day. A sixth producing platform is slated for installation in 2013, which will contribute an additional 185 thousand barrels per day of production capacity.

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 complex, and the nearby Korolev field. The Tengiz field has produced more than 2 billion barrels of oil from a total gross resource of approximately 6 billion barrels. In 2012, TCO produced 528 thousand oil-equivalent barrels per day. Projects are under way to increase production by as much as 260 thousand barrels of oil per day and extend current production rates as reservoir pressure declines.

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 approaching completion, and first oil is anticipated in 2013. In 2012, the partners continued compression facility studies that would raise Phase 1 capacity to 450 thousand barrels per day and signed a gas sales preliminary agreement. Plans for future phases are under evaluation.

      

      

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 2012, net production from these fields averaged 131 million cubic feet of gas per day and 1.3 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 averaged 22 thousand barrels per day in 2012. The 165 thousand-barrel-per-day full field development is progressing and consists of 49 wells, an onshore central processing facility, and a 60-mile pipeline to transport oil to a floating storage and offloading (FSO) vessel. In 2012, we progressed the central processing facility site preparation and grading of the pipeline right-of-way, and completed the first of two dry dock upgrades to the FSO vessel.

Exploration drilling activity continued in the Cepu block in 2012 with the drilling of the Alas Tua East wildcat. Evaluation of the drilling results is ongoing. We continue to evaluate the 2011 Kedung Keris oil discovery.

In August 2011, we signed an 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. An integrated gas project development concept has been selected to develop the Jambaran-Tiung Biru Unit along with the Cendana gas field. The project will support Indonesia’s domestic energy needs.

In November 2012, our Indonesian affiliate, Esso Natuna Ltd., signed a Third Restated Principles of Agreement with the government of Indonesia on key terms and conditions for a new PSC to develop Natuna’s hydrocarbon resources. Discussions to finalize an East Natuna PSC continue.

In 2012, we continued our multiyear exploration program to assess the coal bed methane potential of our acreage in the Barito Basin in Kalimantan (613,000 net acres). Exploration drilling and corehole sampling is anticipated to continue in 2013. During 2012, we completed the integration of the aeromagnetic survey and core data in the Cendrawasih PSC offshore Papua.

      

      

Upstream: Worldwide Upstream Operations, continued

      

      

ExxonMobil, as work operator for the Jansz-Io drilling and completion program, has spud all 10 development wells. Drilling and completion operations are ongoing. Gas will be produced via one of the world’s longest subsea tiebacks, located in 4,430 feet of water.

Gorgon Area Expansion • The exploration and appraisal drilling programs in the Greater Gorgon area continued in 2012. These programs targeted additional high-quality gas resources for a potential expansion of the Gorgon project. In 2012, ExxonMobil participated in three wells on the Northwest Shelf (ExxonMobil interest, 25 percent). Satyr-3 wildcat drilling began in December 2011 and encountered gas in an extension of the existing Satyr-1 discovery in WA-374-P. In July 2012, Satyr-2 encountered gas in subsequent testing of the extent of the Satyr discovery. The third well in the 2012 program, Helene-1, located in WA-37-L, encountered gas in a separate accumulation adjacent to the Gorgon field currently under development. Additional wildcats are planned for 2013.

Scarborough • Development and execution planning continues for the Scarborough LNG project (ExxonMobil interest, 50 percent). Development concepts are being evaluated, including floating LNG.

In 2012, ExxonMobil’s net production from Papua New Guinea averaged 5 thousand barrels of oil per day and 5 million cubic feet of gas per day.

The PNG LNG project (ExxonMobil interest, 33 percent) is scheduled to start up in 2014. At year-end 2012, the project was more than 70 percent complete. Construction milestones in 2012 included completion of the 1.5-mile jetty, the outer shells and roofs of the two LNG tanks, steel erection for the two process trains, and installation of all heavy equipment. The 250-mile offshore pipeline was also completed. Progress continues on the 180-mile onshore pipeline, with more than 125 miles now welded. Drilling has commenced at the Hides natural gas field. Foundation and steelworks at the Hides gas conditioning plant are progressing, and construction has begun at the Gobe production facility. With construction activity at its peak, more than 21,200 people are working together to deliver on project commitments across multiple sites. Forty percent of the workforce are Papua New Guinea citizens.

In 2012, ExxonMobil resumed its exploration program in the Papua New Guinea Highlands. The P’nyang South wildcat encountered gas. Additional development studies have been initiated to assess potential design concepts for the P’nyang resource, which may include a potential PNG LNG third train.

In addition to the PNG LNG project and exploration drilling activities, we continued acquisition of a multiyear seismic program in the Papua New Guinea Highlands to further evaluate our expanding acreage portfolio. More than 55 miles of 2D seismic data were acquired during 2012 to guide future exploration drilling. Planning is under way to acquire additional 2D seismic data in 2013.

		The PNG LNG project is scheduled to start up in 2014, delivering 6.9 million tonnes per annum.