2013: Financial & Operating Summary

We achieved strong financial and operating results in 2013, highlighted by our continued ability to generate strong cash flows that enable industry-leading shareholder distributions. We maintain a long-term perspective on our business with a relentless focus on operational excellence and disciplined investing through the business cycle. We continue to progress a unique and balanced set of profitable growth opportunities, which position us well to deliver long-term shareholder value.

FINANCIAL HIGHLIGHTS

 

(millions of dollars, unless noted)			Earnings After Income Taxes				Average Capital             Employed	(1)			Return on Average Capital Employed (%)	(1)			Capital and Exploration     Expenditures	(1)
Upstream			26,841				152,969				17.5				38,231
Downstream			3,449				24,430				14.1				2,413
Chemical			3,828				20,665				18.5				1,832
Corporate and Financing			(1,538	)			(6,489	)			N.A.				13
Total			32,580				191,575				17.2				42,489

OPERATING HIGHLIGHTS

 

Liquids production (net, thousands of barrels per day)			2,202
Natural gas production available for sale (net, millions of cubic feet per day)			11,836
Oil-equivalent production(2) (net, thousands of oil-equivalent barrels per day)			4,175
Refinery throughput (thousands of barrels per day)			4,585
Petroleum product sales (thousands of barrels per day)			5,887
Chemical prime product sales(1) (thousands of tonnes)			24,063

 

Dividend Growth Since 1984(3)		Total Shareholder Returns(1)

(1) See Frequently Used Terms on pages 90 through 93.

(2) Natural gas converted to oil-equivalent at 6 million cubic feet per 1 thousand barrels.

(3) S&P and CPI indexed to 1984 Exxon dividend.

(4) CPI based on historical yearly average from Bureau of Labor Statistics.

(5) Royal Dutch Shell, BP, Chevron, and Total values are on a consistent basis with ExxonMobil, based on public information.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Delivering Profitable Growth

ExxonMobil is positioned to deliver profitable growth as we start up our major projects and develop our unconventional portfolio in the Upstream and selectively invest in high-value opportunities in Downstream and Chemical. We continue to strategically position the company to deliver shareholder value over the long term, while maintaining our relentless focus on operational excellence.

Operational Excellence Sustaining operational excellence is critical to our ability to deliver profitable growth. We rigorously deploy proven management systems to all of our facilities around the world and incorporate these standard systems into our daily operations to improve safety performance, increase reliability, and lower operating cost.

Upstream We are bringing several major projects online between 2012 and 2017, which are expected to deliver 1 million net oil-equivalent barrels per day of production by 2017, highlighted by the Kearl Initial Development in 2013, Papua New Guinea Liquefied Natural Gas (LNG) in 2014, and the Kearl Expansion project in 2015. We also continue to grow liquids production in our North American unconventional plays. This new production positions us to achieve profitable growth as our percentage of liquids and liquids-linked gas volumes are expected to increase to nearly 70 percent of total production in 2017.

 

 

Downstream We are making selective investments to strengthen our world-class Downstream business, which has been significantly improved through our continuous and disciplined portfolio management process. These investments will increase the production of high-value products, such as ultra-low sulfur diesel, jet fuel, and lubricants, to meet growing demand. Other investments will increase feedstock flexibility and operating efficiency at our advantaged manufacturing sites.

Chemical We are developing projects that capture advantaged feedstocks, deploy lower-cost processes, and increase premium product sales. Key examples include our recently completed Singapore expansion, where we more than doubled our steam-cracking capacity, and the specialty elastomers plant we are constructing in Saudi Arabia. Both of these projects will produce high-value premium products to serve growth markets. In the United States, we continue to progress a world-scale ethane cracker and associated premium polymer capacity at our Gulf Coast facilities to capture the value of advantaged feedstock from natural gas liquids.

We continue to evaluate and progress longer-term opportunities. Our deep portfolio includes additional LNG projects, global unconventional resources, and Russian Arctic developments with the potential to create long-term shareholder value. As we have demonstrated throughout our history, we maintain capital discipline by being selective and progressing only the opportunities with the greatest value.

Rex W. Tillerson, Chairman and CEO

 

 

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

DELIVERING PROFITABLE GROWTH

Operational Excellence

 

Operational excellence underpins everything we do at ExxonMobil and is critical to delivering profitable growth. Driven by our talented and committed workforce, proven management systems are rigorously employed at ExxonMobil facilities across the globe and are incorporated into daily operations. These systems enable continuous improvement in safety performance, increased reliability, and lower operating costs.   CULTURE OF EXCELLENCE   Operational excellence begins with exceptional employees. Backed by comprehensive management systems, the men and women of ExxonMobil form the foundation for strong operational performance. We are proud of the culture of excellence reflected in the daily accomplishments of our employees around the world. It is a culture built by decades of past and current employees’ dedication to doing the right things, the right way, and not accepting compromises to our values.   Maintaining our culture of excellence begins the day a new employee starts working for ExxonMobil. In addition to having access to the depth and breadth of experiences of employees in similar positions around the world, new employees receive intensive training that is designed to incorporate proven best practices.		Comprehensive management systems are consistently applied around the globe, including at the Joliet Refinery (above and on opposite page).
Employees also receive diverse experiences and assignments enabled by our global functional organization, which encourage the sharing of information and talent. Our goal is to retain employees for a long-term career so they can continue to grow
professionally, contribute to our strong experience base, and develop into our next generation of leaders. This philosophy applies equally to local workforce development, where we hire and train people of the developing countries in which we operate.

 

Refining Energy Intensity(1)(2)     (1) Solomon Associates fuels refining data available for even years only. (2) 2013 data estimated by ExxonMobil. (3) Constant year-end 2013 portfolio.		RELIABILITY AND EFFICIENCY   Operational excellence also involves a steadfast commitment to continuously improve the reliability and efficiency of our assets, which leads to improved profitability. We deploy rigorous reliability and maintenance systems that improve operating performance and preserve equipment integrity. Our Upstream reliability performance over the last five years demonstrates the effectiveness of our approach, with improved uptime more than 3 percentage points higher at ExxonMobil-operated assets compared to assets in our portfolio operated by others. This improvement equates to approximately 39 thousand net oil-equivalent barrels per day of additional production.   Another way that our commitment to operational excellence improves profitability is demonstrated by the efficiency of our Downstream assets. Cash operating costs at ExxonMobil refineries have been well below the

 

 

 

 

industry average, driven in large part by energy efficiency improvements. With energy representing as much as 60 percent of the operating cost of a refinery, every incremental improvement in energy efficiency results in increased margins and profitability. Since 2002, we have improved refinery energy efficiency by 10 percent, enabled by the application of our Global Energy Management System and strategic investments.   OPERATIONS INTEGRITY MANAGEMENT SYSTEM   Management systems are deployed throughout our global operations to ensure the consistent application of high operating standards. The Operations Integrity Management System (OIMS) forms the cornerstone of our commitment to operational excellence and provides a solid framework to achieve safe and reliable operations.   OIMS establishes the framework for managing the safety, security, health, and environmental risks in our business, and provides the structure to help us meet or exceed applicable regulations. We continually assess the framework and its effectiveness and incorporate learnings to further improve performance. OIMS is implemented consistently around the world in all business lines, and compliance is tested on a regular basis.

 

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

DELIVERING PROFITABLE GROWTH

Upstream: Developing Advantaged Resources

ExxonMobil’s unique combination of experience and expertise operating in difficult environments sets the stage for project execution success in emerging countries such as Papua New Guinea (PNG). In PNG, this knowledge has enabled ExxonMobil and its partners to surmount a myriad of challenges as they approach start-up of the PNG Liquefied Natural Gas (PNG LNG) project in 2014.

 

The $19 billion development in PNG will produce 6.9 million tonnes per annum (MTA) of LNG for shipment to international markets as well as domestic sales. It is designed to tap world-class reserves from eight separate fields spread across approximately 120 miles. The project includes the construction of a 960-million-cubic-foot- per-day gas conditioning plant in the mountainous Southern Highlands, a liquefaction plant near Port Moresby, and 434 miles of pipeline (253 miles subsea) connecting the two. Successful project development, start-up, and future operations rely on strong relationships with host governments, local communities, and partners, as well as thoughtful planning and proper employment of project management fundamentals.		A vessel is transported to the Hides gas plant site through the unique PNG terrain.

WORLD-CLASS EXECUTION

Through a disciplined approach to project management, the project is well positioned to start up in 2014 despite difficult local conditions. The challenges included zero to low visibility, minimal pre-existing infrastructure, incredibly steep slopes (up to 50-percent grade), as well as geotechnical constraints such as volcanic soil and fault lines. The onshore pipeline, for instance, crosses five faults, which required strain-based-designed pipe and specialized installation procedures. An airfield was constructed in the Highlands to airlift facility modules to build the gas conditioning plant. During the airfield’s construction, more than 9 million cubic meters of earth were moved, and the area experienced enough rainfall to cover the site with 31 feet of water. In addition to technical challenges, a project of this magnitude required global experience to successfully manage a workforce of approximately 20,000 people (speaking more than 40 different languages). Papua New Guinean nationals comprised more than 40 percent of the workforce at its peak.

The project team is preparing for production as construction activities near completion.

 

 

 

COST COMPETITIVENESS

Global LNG projects must be cost-competitive to deliver superior returns. Based on our world-class project execution capabilities and ability to complete projects on schedule, PNG LNG will be at the low end of the cost curve relative to other projects being developed. Even by incorporating the more expensive cost component of the construction in the mountainous Highlands, the cost per MTA for the PNG LNG project will be among the lowest of projects being built in the region.

CAPTURING GROWING ASIAN LNG DEMAND

PNG LNG project revenues and profitability are underpinned by long-term LNG sales contracts covering more than 95 percent of the plant’s capacity. The project is optimally located to serve growing Asian markets where LNG demand is expected to grow by approximately 165 percent between 2010 and 2025, to 370 million tonnes per year. ExxonMobil’s LNG marketing experience and successful track record of developing large LNG projects were instrumental in securing sales with customers in China, Japan, and Taiwan.

EFFECTIVE RELATIONSHIPS WITH THE

GOVERNMENT AND LOCAL COMMUNITIES

 

 

Throughout construction, the project team, with our co-venture partners and positive relationship with the PNG government, has been able to draw on specific industry, socioeconomic, and cultural expertise that has helped position the project for success.

In 2011, we began training approximately 140 talented Papua New Guinean nationals for the production workforce that will operate the facilities for more than 30 years. Our Papua New Guinean employees developed into a team that respects and understands the importance of business fundamentals by maintaining excellence in safety, health and environment, and in ensuring accountability, integrity, and the highest standards of performance.

We created programs to improve maternal health and reduce child mortality rates as well as initiatives designed to promote sustainable business growth. For example, we developed the Enterprise Centre, which has already assisted more than 16,000 Papua New Guinean entrepreneurs. To care for the local environment, the project has adopted international best practices in its approach to biodiversity management, waste management and recycling, and invasive weed and pest control programs.

LEADING LNG CAPABILITIES

The PNG LNG project exemplifies ExxonMobil’s leadership in project execution, advanced technologies, and marketing capabilities. We will continue to enhance our reputation and leading LNG capabilities as we start delivering LNG cargoes from PNG in 2014. Our demonstrated expertise enables effective working relationships with customers, partners, and governments around the world as we progress other LNG opportunities in our portfolio, including expansion opportunities in PNG, to meet growing global demand.

PNG LNG underscores our ability to complete a complex project and develop a world-class resource in a challenging environment on schedule and at a competitive cost. This project will deliver reliable, affordable energy to our customers and create long-term economic value for the people of Papua New Guinea, our partners, and shareholders.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

DELIVERING PROFITABLE GROWTH

Upstream: Developing Advantaged Resources

ExxonMobil has captured a significant position in one of the United States’ premier tight oil plays, the Bakken of North Dakota and Montana. By applying our unconventional expertise to leasehold covering nearly 570,000 acres and leveraging our world-class research organization, we are expanding the resource base and delivering strong, high-margin production growth.

 

STRONG, HIGH-MARGIN GROWTH
Driven by a record 110 wells brought to sales, improving well performance, and an opportunistic acquisition, Bakken gross-operated production increased 81 percent in 2013 to more than 59 thousand oil-equivalent barrels per day. Peak 30-day production rates on new Bakken wells also increased 22 percent in 2013 and have risen 46 percent in the last two years. Since XTO Energy entered the play in 2008, operated production is up fivefold, and our Bakken resource now exceeds more than 900 million net oil-equivalent barrels.   After several years of delineation drilling and optimizing drilling and completion practices, rapidly increasing production reflects our entry into the development stage of the play. We are now completing multiple pad-based wells in geological sweet spots and have significantly increased the number of stimulation stages in the horizontal laterals. In order to optimize productivity, the Bakken		Bakken Production Growth Gross-Operated Production

completion “recipe” is being continuously adjusted based on several

factors, including the number of stages, varying stage length, the sand volume used in each stimulation, the liquid volume and rate, and the proppant type.

The late 2012 Bakken acquisition of more than 190,000 acres is another principal factor contributing to resource and production growth. In addition to increasing our production and acreage by roughly 50 percent, the quality of the acreage and location close to our core operations enabled us to highgrade the drilling inventory and seamlessly integrate the acquired properties. Moreover, we were able to add the properties at an attractive price since part of the transaction involved trading non-core legacy ExxonMobil properties to the seller. This provides a prime example of how the integration of XTO and ExxonMobil enhances shareholder value, and of our disciplined investment approach.

OPERATIONAL EXCELLENCE

We continue to demonstrate operational excellence through relentless efforts to increase drilling, completion, and operations

efficiencies, and through our enduring commitment to safety and environmental performance,		all of which are critical to maximizing value.
Bakken Stages		For example, after entering the Bakken development phase, highlighted by standardized drilling and completion practices and pad drilling, we have seen our drilling days per well decline 28 percent to 22 days since 2011. Coupled with a 39-percent reduction in completion costs per stimulation stage, these efficiencies have contributed to a 25-percent decrease in total drilling and completion costs in the last two years.

Source: ExxonMobil estimates based on IHS and North Dakota Industrial Commission data.

 

 

 

We also are progressing development of Bakken infrastructure to match production growth. In 2013, we completed a major upgrade to our gas gathering facilities in the Nesson area, increasing our ability to capture value from liquids-rich gas, and reducing downtime and gas flaring. Other transportation and gathering initiatives are under way in the Little Missouri and Fort Berthold areas.   INTEGRATING HIGH-IMPACT TECHNOLOGY   XTO and ExxonMobil’s Upstream Research Company are collaborating to increase Bakken recovery and enhance drilling, completion, and operational efficiencies. The unique combination of ExxonMobil’s research capability and XTO’s strong acreage position and operational expertise provides numerous opportunities to test new technologies in the field and deliver proven technologies for immediate benefit.   This partnership forms an important part of the future development strategy of the Middle Bakken and Three Forks reservoirs in the Williston Basin. Ultimately, integrated geoscience and engineering		ExxonMobil is applying its Bakken expertise and technology in areas such as the Vaca Muerta in Argentina and West Siberia in Russia.

teams will rapidly incorporate the results of regional geologic analyses and local stratigraphic trends, fracturing research, and data analytics into planning and completing the highest-impact wells in the most productive areas.

Initial field studies are already under way, with drilling and completion of pilot wells evaluating the optimum spacing of laterals in a drilling unit, and analyzing the potential from the lower benches of the Three Forks formation. Both of these could have a significant impact on our resource and production upside in the Bakken.

In addition, we have begun testing our next generation of completion technology, called XFrac. The Bakken industry standard for hydraulic fracturing completions requires setting dozens of “plugs” in the well to achieve the most effective completion. The plugs must then be drilled out and removed in order to produce the wells. Both of these steps require significant time at a substantial cost. Our proprietary XFrac technology is designed to eliminate the need for plugs, making it possible to complete the well at a lower cost and produce the well sooner, compared to the industry’s current methods.

When combined with XTO’s operational expertise, our proprietary technology provides unique opportunities to optimize Bakken development.

 

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

DELIVERING PROFITABLE GROWTH

Downstream: Strengthening the Portfolio

ExxonMobil’s Downstream investments continue to strengthen our advantaged manufacturing assets by leveraging proprietary technology to increase the yield of high-value products, improve feedstock flexibility, and increase operating efficiency. We carefully evaluate investment opportunities across a range of potential market conditions and advance only those projects likely to provide long-term shareholder value. The success of our disciplined investment approach is demonstrated by our industry-leading Downstream return on capital employed.

 

Since 2005, we have reduced our refining capacity by more than 1 million barrels per day by divesting smaller, less-competitive facilities. The refineries that remain in our portfolio are generally larger, more efficient, and integrated with chemical and lubricant manufacturing facilities. Going forward, we will continue to strengthen our portfolio by investing in attractive return projects at our advantaged sites. These projects will capitalize on ExxonMobil’s technology, scale, and integration.   INCREASING HIGH-VALUE PRODUCT YIELDS   A key focus area for our Downstream investments is increasing the production of high-value products at our advantaged sites. While the demand for some petroleum products, such as gasoline and fuel oil, is expected to decline, demand for high-value products, such as ultra-low sulfur diesel, jet fuel, chemical feedstocks, and lubricants, is expected to continue to grow. Our investments will increase the production of these high-value products to meet future demand and improve profitability. Our fully integrated marketing and sales teams generate consumer demand for these products and help us maximize the value of every molecule that we produce.		Downstream Return on Average Capital Employed(1)     (1) See Frequently Used Terms on pages 90 through 93. (2) Royal Dutch Shell, BP, Chevron, and Total values are estimated on a consistent basis with ExxonMobil, based on public information.

A recent highlight was the commissioning of a new diesel hydrotreater at our Singapore Refinery, which resulted in a significant increase in our ultra-low sulfur diesel production capacity. To build on this success, we are evaluating the construction of a 50-thousand-barrel-per-day delayed coker at our integrated refinery in Antwerp, Belgium. If approved, the new facility will efficiently upgrade low-value fuel oil currently produced at our refineries in northern Europe into higher-value products, including ultra-low sulfur diesel.

Recent investments such as our new hydrotreater in Singapore are contributing to growing production of high-value products. Commissioned in December 2013, the new facility has a capacity of 62 thousand barrels per day.

 

 

 

 

We continue to expand our high-value lubricants business. Sales of our industry-leading products, Mobil 1, Mobil SHC, and Mobil Delvac 1, have almost doubled in the last 10 years and are growing at a faster rate than industry. To further capture profitable growth, we are increasing our capacity to produce high-performance lube basestocks at our facilities in Texas, Louisiana, and Singapore. We are also expanding our lube oil blending capacities in the United States, Finland, and China, supporting the growing demand for finished lubricants in key markets.   REDUCING RAW MATERIAL COST   Downstream investments will also continue to expand refinery feedstock flexibility in order to lower raw material costs and increase margins. Our major focus will remain in North America, where increased crude oil production is creating attractive downstream investment opportunities. ExxonMobil has		ExxonMobil U.S. Gulf Coast Advantaged Crude Refining

the largest combined mid-continent and Gulf Coast refining capacity, and refineries in these regions are benefiting from the growing North American crude oil supply. Our investments in these facilities will further expand our capability to process both light and heavy crude oil.

 

		EXPANDING LOGISTICS CAPABILITY   We are investing to strengthen our crude oil and product logistics capabilities, particularly in North America. For example, in 2013, we acquired a controlling interest in the Wolverine Pipeline system to improve our U.S. mid-continent product logistics. We also recently began construction of a new crude oil rail export terminal in Edmonton to provide cost-advantaged logistics for the growing supply of Western Canadian crude oil. The new terminal will begin operating in 2015 with a capacity of up to 250 thousand barrels per day. Additional investments will expand product export capabilities at our large U.S. Gulf Coast refineries.   WORLD-CLASS OPERATING EFFICIENCY   Underpinned by disciplined investments, worldwide cash operating cost for our portfolio of refineries has been well below the industry average and consistently outperforms competition. Future investments will strengthen our cost advantage. For example, building on our leadership position in cogeneration, we recently started up a new project at our refinery in Augusta, Italy, and are progressing plans for the next project at our refinery in Singapore.   Future downstream investments are expected to increase high-value product yields, reduce raw material cost, and improve operating efficiency at advantaged sites, such as our Baytown Refinery.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

DELIVERING PROFITABLE GROWTH

Chemical: Strategic Investments

We capture market opportunities in our Chemical business by developing world-scale projects that process advantaged feedstocks, deploy lower-cost processes, and increase premium product sales, particularly targeting growth markets. Our strategic and disciplined investment approach delivers superior returns throughout the business cycle and across a variety of market conditions.

 

Our major projects in Singapore, the United States, and Saudi Arabia are all based on the proven combination of advantaged feedstocks, lower-cost processes, and premium products. These projects leverage proprietary technologies to efficiently serve expanding markets and deliver profitable growth.   SINGAPORE   Our recent Singapore expansion illustrates how we identify and approach new capital investments. The project doubled our steam-cracking capacity at the site and significantly increased capacity for premium and specialty products to serve the rapidly growing markets in Asia and beyond.   Enabled by dozens of new proprietary technologies, the world-scale steam cracker can process an unprecedented range of feedstocks, from light gases to heavy liquids, including crude oil. Converting crude oil directly into chemicals provides a cost advantage over naphtha feedstock, the industry standard in Asia. This technology also saves energy and reduces emissions by eliminating the refining steps required to produce naphtha. This crude-cracking approach is an industry first. It is also another step in our ongoing search for advantaged chemical feedstock and demonstrates our ability to innovate and extend our competitive advantage.		An industry-standard steam cracker in Asia receives naphtha feedstock from a refinery. Our Singapore expansion steam cracker is able to process crude directly, bypassing the refinery steps.

Crude cracking produces a wider range of valuable by-products that can be further upgraded to additional specialty products, making this a platform for growth. We are developing plans for additional specialty product lines, including halobutyl rubber to supply the growing tire market, as well as premium resins for adhesive applications. These facilities are planned to start up in 2017.

UNITED STATES

As the largest U.S. chemical manufacturer and natural gas producer, we are progressing a unique project that builds on our proven integration model. In addition to capitalizing on the abundance of low-cost ethane feedstock, it will be enhanced by advantages in integration, scale, and premium products.

The project includes a new world-scale ethane cracker at our site in Baytown, Texas, already the country’s largest integrated refining and chemical manufacturing site. Feedstock and energy supplies will be coordinated with ExxonMobil’s Upstream business. Two world-scale polyethylene lines, the largest in industry, will be added at the nearby Mont Belvieu Plastics Plant to produce a mixed slate of polyolefin products, including metallocene polyethylene.

 

		Based on sustainability and performance advantages, metallocene polyethylene demand grows faster than commodity polyethylene and commands a market premium. As the world’s largest producer of metallocene polyethylene, with manufacturing locations in all major regions, we will leverage our existing global supply chain and market-facing resources to further penetrate growth markets around the world.   Based on our competitive advantages, we believe the Baytown expansion project, with start-up planned for 2017, is well positioned to outperform other announced projects in North America.   Enable and Exceed metallocene polyethylene resins provide stronger, lighter, and lower-cost packaging solutions with reduced environmental impact.

 

 

SAUDI ARABIA

In Saudi Arabia, we are working with our joint venture partner, Saudi Basic Industries Corporation, to build a world-scale specialty elastomers facility. This will produce a broad range of synthetic rubber and related products to help meet the growing demand for rubber-based automotive products created by the significant expansion of road networks and vehicle ownership in the Middle East and Asia. We are integrating proprietary ExxonMobil technologies for premium halobutyl and ethylene propylene diene monomer (EPDM) rubbers into our existing operations at Jubail Industrial City with start-up planned for 2015.

These ExxonMobil processes enable lower-cost production versus competition. For example, our halobutyl technology saves energy and capital investment per tonne of capacity through our proprietary configuration and equipment design. Similarly, our metallocene EPDM technology utilizes fewer process steps and consumes less energy, while

significantly reducing emissions.

 

This project builds on our world-scale commodity assets at the site, which

are based on low-cost feedstocks, to provide specialty products needed

to develop the automotive industry in Saudi Arabia and beyond.

DELIVERING SUPERIOR FINANCIAL PERFORMANCE

Our investments are guided by rigorous analysis of growth

opportunities that leverage integration and capture advantages

in feedstock, lower-cost processes, and premium products,

where we can bring benefits to our customers while

generating industry-leading returns for our shareholders.

The success of this approach is evidenced by our ability

to deliver superior returns on capital employed relative

to competitors throughout the business cycle.

Our recently completed investments, combined with

those under development, will continue to support our

industry-leading position.

 

Chemical: Industry-Leading Returns(1) (10-year average, 2004–2013)
Revenue		Earnings		ROCE (2)
(billions of dollars)		(billions of dollars)		(percent)

(1) Competitor values are estimated on a consistent basis with ExxonMobil and are based on public information. Chemical segments only: Royal Dutch Shell and Total (Total data only available through 2011). Dow Chemical shown on a corporate total basis.

(2) See Frequently Used Terms on pages 90 through 93.

(3) Royal Dutch Shell revenue data only available through 2012.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

 

 

 

 

 

 

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

				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   •   Strong safety and environmental performance   •   Industry-leading earnings of $26.8 billion   •   Proved oil and natural gas reserve additions of 1.6 billion oil-equivalent barrels, replacing more than 100 percent of production for the 20th consecutive year				STRATEGIES   •   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
				•   Added 6.6 billion oil-equivalent barrels of new resource, increasing the overall resource base to more than 90 billion oil-equivalent barrels   •   Exploration discoveries totaling 1.5 billion oil-equivalent barrels in several countries, including Australia, Canada, Tanzania, and the United States   •   Six major project start-ups including the 110-thousand-barrel-per-day Kearl Initial Development project   •   Advanced construction and began commissioning activities at the Papua New Guinea Liquefied Natural Gas project   •   Signed expansion of the 2011 Strategic Cooperation Agreement with Rosneft to include seven additional licenses of exploration acreage in the Russian Arctic   •   Advanced preparation to drill first Kara Sea exploration well in 2014   •   Progressed three North America liquefied natural gas opportunities in Alaska, Western Canada, and at Golden Pass on the Texas Gulf Coast
				UPSTREAM STATISTICAL RECAP		2013		2012		2011		2010		2009
				Earnings (millions of dollars)		26,841		29,895		34,439		24,097		17,107
				Liquids production (net, thousands of barrels per day)		2,202		2,185		2,312		2,422		2,387
				Natural gas production available for sale (net, millions of cubic feet per day)		11,836		12,322		13,162		12,148		9,273
				Oil-equivalent production(1) (net, thousands of barrels per day)		4,175		4,239		4,506		4,447		3,932
				Proved reserves replacement ratio(2)(3) (percent)		106		124		116		211		100
				Resource additions(2) (millions of oil-equivalent barrels)		6,595		4,012		4,086		14,580		2,860
				Average capital employed(2) (millions of dollars)		152,969		139,442		129,807		103,287		73,201
				Return on average capital employed(2) (percent)		17.5		21.4		26.5		23.3		23.4
				Capital and exploration expenditures(2) (millions of dollars)		38,231		36,084		33,091		27,319		20,704
				(1) Natural gas converted to oil-equivalent at 6 million cubic feet per 1 thousand barrels. (2) See Frequently Used Terms on pages 90 through 93. (3) Proved reserves exclude asset sales. Includes non-consolidated interests and Canadian oil sands. Note: Unless otherwise stated, production rates, project capacities, and acreage values referred to on pages 16 through 47 are gross.

 

 

 

 

BUSINESS OVERVIEW

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

Demand for oil and other liquid fuels is forecast to increase by about 25 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. Global demand for natural gas is likely to increase by about 65 percent by 2040. About 65 percent of the growth in natural gas supplies through 2040 is expected to be from unconventional sources, which will account for one-third of global production by 2040. Meanwhile, liquefied natural gas (LNG) volume is expected to triple by 2040, contributing approximately 15 percent of global gas supply. Meeting the world’s growing demand for energy presents a tremendous challenge that will require a long-term view, significant investment, and continuing innovation to develop conventional and unconventional resources.

ExxonMobil is well positioned to meet this challenge while delivering sustained, long-term value for our shareholders through the disciplined execution of our Upstream strategies across exploration, development, production, natural gas and power marketing, and research activities. We begin by identifying and selectively capturing the highest-quality resources, testing for technical and commercial quality as well as materiality. We then apply a disciplined approach to investing and cost management. Proven project management systems incorporate best practices developed from our extensive worldwide experience to rigorously manage our global project portfolio from initial discovery to start-up.

We have a steadfast commitment to develop and apply high-impact technologies in areas such as subsurface imaging, reservoir modeling, and well completions. This enhances our ability to find, efficiently develop, and produce new resources from some of the most challenging reservoirs. These technologies also enable us to improve the economic performance of our existing assets.

We apply robust operating and risk management systems to maximize the profitability of our existing oil and gas production. Over the last five years, our operated-facility downtime has been close to 25-percent better than fields operated by others in which we hold an interest, which equates to approximately 39 thousand net oil-equivalent barrels per day.

With our detailed knowledge of global energy markets, we are also able to capitalize on growing natural gas and power markets. In 2013, we sold more than 14 billion net cubic feet per day of gas across 35 countries including participating in LNG operations that delivered more than 62 million tonnes to global markets. Our industry leadership in the application of cogeneration technology enables the capture of additional value by increasing efficiency and reducing emissions.

Our Upstream strategies, supported by a relentless focus on effective risk management, safety, and operational excellence, are designed to deliver superior results through the long term.

 

Global Liquids Supply by Type		Global Natural Gas Production by Type
Source: ExxonMobil, 2014 The Outlook for Energy: A View to 2040		Source: ExxonMobil, 2014 The Outlook for Energy: A View to 2040

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Opportunity Capture

Integration of technical expertise, extensive global databases, and industry-leading research capabilities enables ExxonMobil to identify and selectively capture the highest-quality resources across all resource types and environments. The depth and breadth of our worldwide experience as explorers, developers, producers, and technology innovators position us favorably as a partner of choice for resource owners and other organizations.

2013 OPPORTUNITY CAPTURES

In 2013, we captured 15 new opportunities spanning conventional and unconventional plays to build on our industry-leading resource base. At year-end 2013, our exploration acreage totaled more than 61 million net acres in 32 countries. Some of the new acreage positions that were established are in Russia, Brazil, Gabon, Liberia, South Africa, and the Faroe Islands.

Brazil • We participated in the Brazil Tender Round 11 in 2013 and successfully acquired two blocks in the Potiguar and Ceara basins for a combined 190,000 net acres. ExxonMobil will operate these blocks.

Canada • In February 2013, we completed the acquisition of Celtic Exploration Ltd., expanding our presence in Western Canada through the addition of roughly 545,000 net acres in the liquids-rich Montney Shale and 104,000 net acres in the Duvernay Shale unconventional plays. In addition, ExxonMobil acquired an interest in the in situ Steam-Assisted Gravity Drainage Clyden oil sands lease adding 226,000 net acres of high-quality oil resource.

Faroe Islands • ExxonMobil expanded its position in 2013 and acquired a 26-percent interest in license L016 in the Faroe Islands, covering 249,000 net acres.

Gabon • ExxonMobil entered Gabon by acquiring a 30-percent stake in the deepwater Arouwe Block encompassing 327,000 net acres.

Liberia • ExxonMobil entered Liberia by acquiring an 83-percent interest in Liberia Block 13, adding approximately 520,000 net acres in a deepwater play.

GLOBAL UPSTREAM PORTFOLIO

 

 

 

 

 

Russia • ExxonMobil is working with Rosneft on the exploration potential in the Kara Sea (10.35 million net acres) and the Black Sea Tuapinskiy (990,000 net acres), as part of the original Strategic Cooperation Agreement (SCA). Additionally, agreements were signed to increase the scope of the SCA, including seven new blocks in the Russian Arctic.   South Africa • ExxonMobil acquired a 75-percent interest and 2.1 million net acres in the Tugela South deepwater block offshore South Africa, representing another new country entry in 2013.   U.S. Offshore • We expanded our position in the Gulf of Mexico by a combined 75,000 net acres. We were awarded 11 Offshore Continental Shelf (OCS) blocks in Sale 229 and Sale 227 and concluded a six-block farm-in agreement.   U.S. Onshore • In April, we acquired 12,000 net acres of additional Woodford Shale acreage in southern Oklahoma, bringing our total acreage position to more than 270,000 net acres in the liquids-rich Ardmore/Marietta area.

RESOURCES

In 2013, we continued to build our diverse global portfolio of resources and reserves by adding 6.6 billion oil-equivalent barrels. After adjusting for production, asset sales, and revisions to existing fields, the resource base totals more than 90 billion oil-equivalent barrels. Proved reserves comprise approximately 28 percent of the resource base, or 25.2 billion oil-equivalent barrels.

The addition of an average of 4.8 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 exploration drilling, capture of undeveloped resources, strategic acquisitions, and increased recovery from existing fields. In 2013, resources were added in Argentina, Australia, Canada, Nigeria, Norway, Tanzania, the United Arab Emirates, and the United States.

Our exploration drilling program added 1.5 billion oil-equivalent barrels in 2013, with additions from multiple resource types around the world. Additions from exploration drilling averaged approximately 2 billion oil-equivalent barrels per year over the last decade.

 

Resource Additions/Acquisitions(1)		Resource Base Distribution(1)		Resource Base Distribution(1)
By Resource Type		By Region		By Resource Type
(percent, oil-equivalent barrels added)		(percent, oil-equivalent barrels)		(percent, oil-equivalent barrels)

(1) See Frequently Used Terms on pages 90 through 93.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Opportunity Capture, continued

 

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 oil and gas, unconventional gas and oil, and heavy oil/oil sands, which comprise 71 percent of the total. LNG and deepwater account for about 14 percent of the total resource base. The remaining 15 percent is made up of arctic and acid/sour gas resources.		RESOURCE BASE CHANGES (1)
		(billions of oil-equivalent barrels)		2013				5-Year Average
		Resource additions/acquisitions			6.6				6.4
		Revisions to existing fields			(0.2	)			(0.6	)
		Production			(1.6	)			(1.6	)
		Sales			(1.2	)			(0.6	)
		Net change versus year-end 2012			3.6				3.6
		Proved Reserves Replacement Ratio(1)(2)   (percent of annual production replaced with proved reserves additions)

PROVED RESERVES

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.

In 2013, we replaced 103 percent of the reserves we produced, including the impact of asset sales. We added 1.6 billion oil-equivalent barrels to proved reserves (76 percent liquids) while producing 1.6 billion oil-equivalent barrels. Excluding asset sales, our proved reserves replacement ratio was 106 percent. Key proved reserve additions resulted from the funding of the Abu Dhabi Upper Zakum 750 project and the associated license extension, and North America unconventional activities.

ExxonMobil added 10.3 billion oil-equivalent barrels to proved reserves over the last five years, more than replacing production over that time period. The development of new fields and extensions of existing fields have resulted in the addition of an average of 1.1 billion oil-equivalent barrels per year to proved reserves.

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 20 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.

 

Proved Reserves Distribution(1)		Proved Reserves Distribution(1)		Proved Reserves Distribution(1)
By Region		By Resource Type		By Hydrocarbon Type
(percent, oil-equivalent barrels)		(percent, oil-equivalent barrels)		(percent, oil-equivalent barrels)

(1) See Frequently Used Terms on pages 90 through 93.

(2) Includes asset sales.

 

Global Upstream Portfolio

Our disciplined investment approach combines systematic project assessment with technical and commercial expertise. We 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. We apply this approach across the asset life cycle from initial resource capture and project execution through production operations. Our primary focus is to deliver superior investment returns over the long term.

 

PRODUCTION VOLUMES   Net liquids production was up 17 thousand barrels per day versus 2012 as start-up of the Kearl Initial Development project, ramp-up of recent West Africa projects, increasing U.S. unconventional liquids production, and improved uptime performance more than offset field decline. Net natural gas production was down 4 percent as expected lower U.S. production and field decline were partially offset by lower facility downtime, higher weather-related demand, and project start-ups. Net oil-equivalent production of 4.2 million barrels per day decreased 1.5 percent versus 2012 consistent with our projections.   Near-term activity will focus on starting up 14 projects in 2014 and 2015, highlighted by the Papua New Guinea Liquefied Natural Gas, Sakhalin-1 Arkutun-Dagi, Banyu Urip, and Kearl Expansion projects. We will continue to develop our significant, liquids-rich North American unconventional resources. We will also continue to pursue attractive opportunities to increase volumes from existing assets through new drill wells, workovers of existing wells, and secondary and tertiary recovery programs.				FOCUS ON PROFITABILITY   We have focused efforts to improve long-term unit profitability and have made strategic choices to meet this objective. We have a portfolio of production volumes across a range of profitability. We first maximize the production of our high-profit volumes by running our facilities at the highest uptime possible. Application of technologies to reduce costs and improve recovery is another key enabler to producing high-profit volumes. In some instances, improved fiscal or contractual terms are needed to improve profitability. In these cases, we engage the resource owners to develop mutually beneficial solutions, as we have done with the Upper Zakum concession in the United Arab Emirates. Another example of improving long-term profitability is our decision to continue shifting capital from dry gas to liquids-rich plays in North America, which reduces total oil-equivalent production but improves the profitability mix as we increase the production of higher-margin liquids.

Excluding the impact of the United Arab Emirates onshore concession expiry and the Iraq West Qurna I partial divestment, liquids production is anticipated to grow by 2 percent in 2014 and by 4 percent per year on average from 2015 through 2017. Natural gas production is anticipated to decline by 2 percent in 2014 and to grow by 1 percent per year on average from 2015 through 2017.

The forward-looking projections of production volumes in this document reflect 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, and entitlement volume effects under certain production sharing contracts and royalty agreements.   The production we are bringing online from our major projects and other activities positions us to achieve profitable growth as our liquids and liquids-linked gas volumes as a percentage of total volumes are projected to increase to nearly 70 percent in 2017.		Production Outlook(1)   (millions of oil-equivalent barrels per day, net)

 

Total (millions of oil-equivalent barrels per day, net)			4.0	(1)			4.0				4.1				4.2				4.3

(1) 2013 production excludes the impact of United Arab Emirates onshore concession expiry and Iraq West Qurna I partial divestment. Production based on 2013 average price ($109 Brent).

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Global Upstream Portfolio, continued

 

2013 MAJOR DEVELOPMENT PROJECTS   ExxonMobil participated in six major start-ups in 2013 and we plan to bring 21 more major projects online by 2017. These projects, along with our 2012 start-ups, are expected to deliver 1 million net oil-equivalent barrels per day to our production volumes by 2017.   Kearl Initial Development • (Combined ExxonMobil and Imperial Oil interest, 100 percent) Kearl Initial Development started up in April 2013. It is anticipated to produce 110 thousand barrels of bitumen per day and employs a number of technology innovations, including a proprietary froth treatment process that eliminates the need to build an upgrader. Ongoing expansion and planned future debottlenecking have the potential to increase production up to 345 thousand barrels per day.   Kashagan Phase 1 • (ExxonMobil interest, 17 percent) Phase 1 of the Kashagan Development started up in September 2013 and reached a maximum gross production level of approximately 80 thousand barrels per day. Following a brief period of production, the field was shut-in due to a leak in the main gas pipeline. Work is progressing on the repair options and production reinstatement.		Major Project Production Outlook Production by Start-Up Year(1)     (1) Excludes impact of future divestments and OPEC quota effect. Production based on 2013 average price ($109 Brent).

Syncrude Aurora North Mine Sustaining Project • (Imperial Oil interest, 25 percent) Aurora North oil sands ore processing plant relocations and tailings management facility start-ups were completed in October 2013. These projects enable sustained production rates of approximately 215 thousand barrels of bitumen per day.

Telok • (ExxonMobil interest, 50 percent) Located offshore Malaysia, Telok first gas was achieved in March 2013 ahead of plan. Eight wells have been successfully drilled, and seven completions tied in and flowing full well stream gas to the host platform Guntong E at an estimated combined rate of 275 million cubic feet per day.

 

Kipper Tuna and Turrum • (ExxonMobil interest, Tuna and Turrum 50 percent; Kipper 32.5 percent) The Kipper Tuna and Turrum projects started up in 2013 with initial production from the Tuna and Turrum fields. Located in the Gippsland Basin in Australia, the projects include a new offshore platform and subsea tieback. Peak production will be achieved following the completion of development drilling at Turrum and start-up of onshore gas conditioning facilities.		PROJECT EXECUTION PERFORMANCE – EXXONMOBIL PROJECTS
		(percent of plan, 2009-2013 average)		Cost				Schedule
		ExxonMobil Operated			102				106
		Operated by Others			133				139

 

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

 

 

 

		MAJOR PROJECT START-UPS(1)
						Facility Capacity (Gross)								ExxonMobil												Facility Capacity (Gross)								ExxonMobil
						Liquids (KBD)				Gas (MCFD)				Working Interest (%)												Liquids (KBD)				Gas (MCFD)				Working Interest (%)
		2012-2013 (Actual)																				2017+ (Projected)
		Angola		Kizomba Satellites Phase 1			100				–				40			n				Angola		AB32 Kaombo Split Hub			250				–				15			l
		Australia		Kipper Tuna			15				175				40			n				Australia		Gorgon Area Expansion			10				915				25			l
				Turrum			20				200				50			n						Scarborough			–				1,030				50			n
		Canada		Kearl Initial Development			110				–				100			n				Canada		Aspen			90				–				100			n
				Syncrude Aurora North Mine			215				–				25			p						Cold Lake Grand Rapids			40				–				100			n
				Sustaining Project
		Kazakhstan		Kashagan Phase 1			370				450				17			l						Firebag			380				–				70			n
		Malaysia		Telok			–				430				50			n						Hebron			150				–				36			n
		Nigeria		Satellite Field Development			70				–				40			n						Kearl Debottleneck			125				–				100			n
				Phase 1																				Mackenzie Gas Project			10				830				56			n
				Usan			180				–				30			l						Syncrude Aurora South			210				–				25			p
		2014-2016 (Projected)																						Phases 1 and 2
		Angola		Cravo-Lirio-Orquidea-Violeta (CLOV)			160				–				20			l						Syncrude Mildred Lake Extension			210				–				25			p
																						Indonesia		Cepu Gas			5				220				41			p
				Kizomba Satellites Phase 2			85				–				40			n						Natuna			–				1,100				**			n
		Australia		Gorgon Jansz			20				2,765				25			l				Iraq		West Qurna I			1,600				–				25			p
		Canada		Cold Lake Nabiye Expansion			50				–				100			n				Kazakhstan		Aktote			50				850				17			l
				Hibernia Southern Extension			55				–				27			n						Kashagan Future Phases			1,260				–				17			l
				Kearl Expansion			110				–				100			n						Tengiz Expansion			260				–				25			l
				Syncrude Mildred Lake Mine Sustaining Project			180				–				25			p						Tengiz Sustaining Project			395				–				25			l
		Indonesia		Banyu Urip			165				15				45			n				Nigeria		Bonga North			100				60				20			l
		Malaysia		Damar Gas			5				200				50			n						Bonga Southwest			225				15				16			l
		Nigeria		Erha North Phase 2			60				–				56			n						Bosi			140				260				56			n
		Norway		Aasgard Subsea Compression			40				415				14			l						Satellite Field Development Phase 2			80				–				40			n
		Papua		PNG LNG			30				1,000				33			n						Uge			110				20				20			n
		New  Guinea
		Qatar		Barzan			90				1,400				7			p						Usan Future Phases			50				–				30			n
		Russia		Sakhalin-1 Arkutun-Dagi			90				–				30			n				Romania		Domino			–				630				50			n
		U.S.		Hadrian South			5				300				47			n				Russia		Sakhalin-1 Future Phases			–				800				30			n
				Heidelberg			80				80				9			l						Sakhalin-1 Odoptu Stage 2			55				–				30			n
				Julia Phase 1			30				–				50			n				Tanzania		Tanzania Block 2			–				1,000				35			l
				Lucius			100				150				15			l				United Arab Emirates		Upper Zakum 750			750				–				28			p
				Point Thomson Initial Production System			10				200				37			n				U.S.		Alaska LNG			60				3,500				36			l
		KBD  = Thousand barrels per day        MCFD = Million cubic feet per day

 

n   ExxonMobil Operated             l  Co-Venturer Operated             D  Joint Operations            **  Pending Final Agreements

 

(1)	The term “project” as used in this publication can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations

 

ExxonMobil has an interest in exploration and production acreage in 36 countries and production operations in 23 countries.   THE AMERICAS   Our Americas portfolio includes conventional onshore fields, ultra-deepwater developments, numerous unconventional gas and oil opportunities, and oil sands and heavy oil plays. Operations in the Americas accounted for 33 percent of net oil-equivalent production and 21 percent of Upstream earnings in 2013.		AMERICAS HIGHLIGHTS		2013				2012				2011
		Earnings (billions of dollars)			5.6				5.5				7.8
		Proved Reserves (BOEB)			12.0				11.8				10.8
		Acreage (gross acres, million)			46.2				47.0				50.2
		Net Liquids Production (MBD)			0.7				0.7				0.7
		Net Gas Available for Sale (BCFD)			3.9				4.2				4.3
		Americas Production   (millions of oil-equivalent barrels per day, net)

 

 

UNITED STATES

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 offshore

Gulf of Mexico, the

Gulf Coast, the

Rockies, the

mid-continent,

California, Alaska,

and

Appalachia.

Our U.S.

portfolio includes

mature conventional assets,

emerging unconventional

developments, and new

deepwater developments. 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,

eight of which are estimated to

contain recoverable resources of

greater than 1 billion oil-equivalent

barrels. Future developments are

also planned from ExxonMobil’s

extensive deepwater Gulf

of Mexico acreage position.

Gulf of Mexico/Gulf Coast

2013 average net production in the Gulf of

Mexico was 43 thousand barrels of liquids

per day and 159 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 continues in the Keathley Canyon (KC) area. We are developing the Hadrian-5 discovery under a unitization agreement

as part of the Anadarko-operated Lucius development (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. Start-up for both developments is planned for 2014.

ExxonMobil and its co-venturers continue to incorporate appraisal drilling results into concept selection for development of the Hadrian North oil discovery (ExxonMobil interest, 50 percent), which is situated on blocks KC-918 and KC-919.

The Julia Phase 1 project (ExxonMobil interest, 50 percent) in the Walker Ridge (WR) area was fully funded in 2013, as a subsea tieback to the Chevron-operated Jack-St. Malo host facility on WR-718. First oil production is planned for 2016.

ExxonMobil is also participating in the Anadarko-operated Heidelberg project (ExxonMobil interest, 9 percent), which was fully funded in 2013. The project develops resources located in a five-block unit in Green Canyon and is planned to start up in 2016.

We continue to expand and evaluate our substantial exploration portfolio of 1.5 million net acres in the deepwater Gulf of Mexico with investments in advanced seismic data to further enhance understanding of the subsurface. ExxonMobil was the high bidder on four Offshore Continental Shelf (OCS) blocks in Sale 229 and seven OCS blocks in Sale 227.

Conventional • The Mobile Bay development offshore Alabama contributed net production of 121 million cubic feet of gas per day during 2013. We continue to realize 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, progressed federal permitting to add up to 15.6 million tonnes per annum of proposed export capacity 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. The project received approval to export to countries with Free Trade Agreements (FTA) with the United States in 2012 and is awaiting approval to export to non-FTA countries. In 2013, the Federal Energy Regulatory Commission (FERC) Pre-Filing Environmental Review Process was initiated.
		The Golden Pass LNG terminal in Sabine Pass, Texas, progressed federal permitting to add up to 15.6 million tonnes per annum of proposed LNG export capacity.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

U.S. Onshore Texas and Louisiana

ExxonMobil is a leading producer in Louisiana and Texas with a strong position in multiple unconventional gas plays and the Permian Basin. In 2013, onshore net production in Texas and Louisiana averaged 102 thousand barrels of liquids per day and 1.8 billion cubic feet of gas per day.

Conventional • ExxonMobil is a leading leaseholder and producer in the Permian Basin. After ramping up activity to eight drilling rigs in 2013, we completed more than 130 wells across multiple fields, primarily Russell, Goldsmith, Fullerton, Cornell, and Mahoney. More than 65 workover rigs are also active in the Permian, increasing production by opening up additional zones with fracture stimulation treatments, most significantly in the Fullerton and Robertson areas. We are also optimizing development and expanding infrastructure in our carbon dioxide projects in the Central Basin Platform area and in East Texas, and continue to evaluate the results of the Means Residual Oil Zone project that started up in late 2011.

Unconventional • ExxonMobil holds 224,000 net acres in the Haynesville/Bossier Shale of East Texas and Louisiana, where we continued to realize the benefits of our drilling and completion improvements. We also continued well spacing tests in both the Haynesville and overlying Bossier Shale reservoir with encouraging early results.

In the Barnett Shale play in North Texas, we completed 95 wells in 2013 across our leasehold of 218,000 net acres, primarily focusing on the liquids-rich gas areas. In the Freestone tight gas trend, ExxonMobil holds 319,000 net acres. We brought 11 wells online in 2013 and completed upgrades to both sweet and sour gas infrastructure in the Beargrass area to handle high-volume horizontal completions.

In the Permian, we continue to evaluate unconventional potential across our acreage, highlighted by the Wolfcamp, Wolfbone, Wolfberry, and Bone Springs reservoirs. In 2013, we completed nine Bone Springs wells that had average 30-day rates of approximately 600 oil-equivalent barrels per day.

Mid-Continent and Appalachia

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 2013 was 88 thousand barrels of liquids per day and more than 1.5 billion 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 one of the world’s largest helium recovery and physical solvent gas sweetening plants. Implementation of a project to improve environmental performance of the Shute Creek plant’s compressor engines started up in early 2012, and record carbon dioxide sales of more than 340 million cubic feet per day were reached in late 2013. The LaBarge facilities processed an average of 629 million cubic feet of inlet gas per day in 2013.

ExxonMobil’s proprietary Controlled Freeze Zone (CFZ) technology underwent rigorous testing from 2012 to 2013 at the Shute Creek commercial demonstration plant. CFZ is a single-step cryogenic separation process with the potential to make carbon capture and storage more affordable and significantly reduce carbon dioxide and hydrogen sulfide content in the natural gas stream while meeting or exceeding product purity specifications. The testing also demonstrated the ability to reinject the acid gas product stream, a key differentiating attribute of this technology.

Unconventional • The Bakken Shale remained one of our most active unconventional programs in 2013 with well completions and production volumes reaching all-time highs. ExxonMobil currently holds 570,000 net acres of high-quality resource in this play. Through the deployment of 10 rigs and the acquisition of more than 190,000 acres from Denbury Resources, gross-operated production in the Bakken increased 81 percent from 2012 to 59 thousand barrels of oil per day in 2013.

The liquids-rich Woodford Shale in the Ardmore Basin of southern Oklahoma was another one of our active areas in 2013. We operated 12 rigs across our more than 270,000 net acres of leasehold and continue to successfully delineate the Woodford and Caney reservoirs across our core Ardmore and Marietta areas. We are also progressing infrastructure projects to optimize the liquids-rich production from this area.

In the Fayetteville Shale, pad drilling, optimized well spacing, and improved drilling processes are increasing efficiencies as development proceeds across our 490,000 net acres.

 

 

ExxonMobil holds a material acreage position in the Marcellus Shale of 589,000 acres across Pennsylvania and West Virginia and 84,000 acres in the promising Utica Shale in Ohio. We continue to be encouraged by early drilling results. In 2013, we commissioned and started up a 125-million-cubic-foot-per-day cryogenic gas plant in Butler County, which will increase our returns in the Marcellus area through the capture of additional natural gas liquids. In Utah, Colorado, and New Mexico, development of the more than 1 million net acres in the Uinta, Piceance, Raton, and San Juan has continued.

California

Net production from fields both onshore and offshore California averaged 91 thousand barrels of liquids per day and 23 million cubic feet of gas per day during 2013. 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 2013, development drilling was resumed at the SYU Harmony drilling rig following several upgrades that resulted in a 70-percent increase in the rig’s reach capacity. Onshore California, we are progressing plans to commence further development drilling in 2014.

ExxonMobil also has a 48-percent equity share in Aera Energy LLC’s operations, comprising eight fields and about 11,000 wells that produce 61 thousand net oil-equivalent barrels per day of a mixture of heavy and conventional oil with associated natural gas.

Alaska

Average net production in Alaska was 106 thousand barrels of liquids per day in 2013. ExxonMobil is the largest holder of discovered natural gas resources on the North Slope of Alaska. The initial development phase of the Point Thomson project is progressing with site preparation and an air strip completed, permanent housing camp occupied, and large processing module fabrication in progress. Together with the State of Alaska and its co-venturers, ExxonMobil is continuing to progress the Alaska LNG project to commercialize Alaskan gas resources.

CANADA

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.

Offshore Canada Operations

The Hibernia field (ExxonMobil interest, 33 percent) offshore Newfoundland is operated by Hibernia Management and Development Company Ltd., utilizing ExxonMobil personnel and processes. Hibernia’s net production averaged 29 thousand barrels of oil per day in 2013. Progress continued on the Hibernia Southern Extension project (ExxonMobil interest, 27 percent), which consists of a subsea tieback to the existing Hibernia platform and will access recoverable resources of approximately 170 million gross oil-equivalent barrels. Subsea equipment installation was completed and subsea drilling commenced. Start-up is expected in 2014.

 

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 gross capacity of 150 thousand barrels per day. In 2013, construction of the concrete gravity-based structure continued in Newfoundland, while fabrication of topsides modules in Newfoundland and Korea commenced. Start-up is expected in 2017.   The Hebron project, which will utilize a gravity-based structure (shown under construction), will have gross production capacity of 150 thousand barrels per day and will be located in 300 feet of water offshore Newfoundland.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

The co-venturer-operated Terra Nova development (ExxonMobil interest, 19 percent) produced 7 thousand net barrels of oil per day in 2013. Located in 300 feet of water, Terra Nova consists of a unique, harsh-environment-equipped floating production, storage, and offloading (FPSO) vessel.

The ExxonMobil-operated Sable Offshore Energy project (ExxonMobil interest, 51 percent; Imperial Oil interest, 9 percent) in Nova Scotia comprises five producing fields. Net production in 2013 averaged 53 million cubic feet of gas per day and 2 thousand barrels of associated natural gas liquids per day.

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 2013, we continued interpretation of 3D seismic data and progressed plans for the first exploration well.

Onshore Canada Operations

In 2013, the Cold Lake heavy oil field in Alberta (Imperial Oil interest, 100 percent) achieved production of 127 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 4,200 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. The next expansion of the Cold Lake development is the Nabiye project, which was 65-percent complete at year end and will increase capacity by 50 thousand barrels of bitumen per day. Experimental pilots are currently under way to test solvent-based recovery technologies that would further enhance recovery and lower greenhouse gas emissions.

The Syncrude oil sands mining operation (Imperial Oil interest, 25 percent) produced synthetic crude averaging 65 thousand net barrels per day in 2013. 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 (ExxonMobil and Imperial Oil interest, 100 percent) is developing a world-class resource in northern Alberta expected to exceed 4 billion barrels. Production of mined diluted bitumen from the first of three froth treatment trains began in April 2013. Two additional bitumen froth trains came online in sequence as planned, reaching total production from the initial development of 100 thousand barrels per day by year end. Fabrication and construction are well advanced 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 2013, 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 226,000 net acres of high-quality in situ oil sands in 2013. 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.   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 ongoing production from a pilot project consisting of eight horizontal production wells and associated facilities. Production started in August 2012 from the 30-million-cubic-foot-per-day capacity facility.   Nabiye is the next expansion phase of the Cold Lake development.

 

 

ExxonMobil began development of the 649,000 net acres in the Montney and Duvernay that were added in February 2013 through the acquisition of Celtic Exploration Ltd. Throughout the winter months of 2013, two new wells were completed in the Montney and Duvernay. By year-end 2013, four drilling rigs were active in this liquids-rich area with the potential to increase further.

Imperial Oil and ExxonMobil are in the early stages of project assessment and planning for a proposed LNG plant in Western Canada. Through the jointly owned affiliate WCC LNG Ltd., ExxonMobil and Imperial Oil received an export permit in 2013 from the National Energy Board to export up to 30 million tonnes of LNG per year for 25 years.

 

SOUTH AMERICA   Argentina In Argentina, ExxonMobil holds a 51-percent interest in the Chihuidos concession. In June 2013, we sold our 23-percent working interest in the Aguarague concession to YPF. During 2013, we sold net daily gas production of 28 million cubic feet from these concessions into markets in Argentina. We also continued our exploration drilling and well-testing campaign in the highly-prospective Vaca Muerta shale formation in the Neuquen Basin where ExxonMobil holds more than 850,000 net acres. Drilling commenced on two ExxonMobil-operated wells with completion and testing activities ongoing on previously drilled wells. Drilling and testing results are being evaluated with additional wells planned for 2014.   Brazil ExxonMobil captured a 50-percent operating interest in two deepwater blocks in Brazil Tender Round 11 in 2013. Seismic operations are planned for 2014 and 2015.   Colombia ExxonMobil has an interest in four blocks and a technical evaluation agreement for one block in the emerging tight liquids play of the Magdalena Basin. An initial short-term test of the first exploration well and additional drilling are planned for 2014.		In 2013, we continued our exploration drilling program in the highly-prospective Vaca Muerta shale formation in Argentina.

		In the heavy oil play, ExxonMobil holds a technical evaluation agreement in Block CPE-3 onshore Colombia covering more than 3.2 million net acres. In 2013, 2D seismic data was collected to evaluate potential core hole locations. Exploratory core hole drilling is expected to be completed in 2014.   Guyana ExxonMobil holds a 50-percent operating interest in the Stabroek deepwater block (3.3 million net acres) offshore Guyana. In 2013, we completed 3D seismic data acquisition to evaluate its potential.   Venezuela 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 a request for arbitration against Venezuela with the International Centre for Settlement of Investment Disputes (ICSID) in September 2007. The ICSID arbitration is ongoing.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

 

EUROPE   ExxonMobil is one of Europe’s largest producers of oil and gas. Key assets include North Sea oil and natural gas production operations and onshore natural gas production in the Netherlands and Germany. In 2013, European operations accounted for 18 percent of ExxonMobil’s net oil and natural gas production and 13 percent of Upstream earnings.   ExxonMobil continues to progress exploration activities and development projects in Europe. We also continue to increase recovery from existing producing assets through work programs and the implementation of new technology. We continue to evaluate the exploration potential near our 2012 Domino gas discovery in the Romanian Black Sea and have continued to evaluate significant unconventional		EUROPE HIGHLIGHTS		2013				2012				2011
		Earnings (billions of dollars)			3.4				4.0				7.1
		Proved Reserves (BOEB)			2.3				2.5				2.7
		Acreage (gross acres, million)			21.2				43.7				44.1
		Net Liquids Production (MBD)			0.2				0.2				0.3
		Net Gas Available for Sale (BCFD)			3.3				3.2				3.4
		Europe Production   (millions of oil-equivalent barrels per day, net)

 

natural gas and oil opportunities in Germany. Additionally, ExxonMobil provides natural gas supply to the

European market through liquefied natural gas (LNG) from our joint ventures with Qatar Petroleum, including

receiving terminals in the United Kingdom and Italy where ExxonMobil has equity interests.

Faroe Islands

ExxonMobil holds approximately 783,000

net acres through a 49-percent interest in

license L006, a 50-percent interest

in licenses L009 and L011, and a

26-percent interest in license L016.

The 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.

Plans are being finalized to complete drilling

of Brugdan-2 in 2014.

Germany

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 2013,

these fields generated an average net

production of 428 million cubic feet per

day. During the year, we also reduced our

operational footprint through a series

of infrastructure rationalization and

upgrade projects. Most notably,

the consolidation of the

Grossenkneten and NEAG sour

gas plants has now been

completed. All of our current

sour gas production now

routes through the

Grossenkneten gas plant.

 

 

 

 

 

Our subsidiaries in Germany hold 4 million net acres of exploration acreage in Lower Saxony, Hamburg, and North Rhine Westphalia. These contain potential shale gas, tight gas, tight liquids, and coal bed methane exploration plays. Future exploration activities await the issuance of permits for hydraulic fracturing.

Greenland

In 2012, ExxonMobil completed the geological evaluation of Blocks 4 and 6 in the Disko West area, offshore Greenland, and withdrew from the licenses in 2013 having met all commitments.

Ireland

ExxonMobil has interests in two Frontier Exploration Licenses (FEL): Dunquin FEL 3/04 (ExxonMobil interest, 25.5 percent) and Cuchulain FEL 1/99 (ExxonMobil interest, 36 percent). These licenses cover approximately 220,000 net acres in the Porcupine Basin, approximately 125 miles off the southwest coast of Ireland. The 44/23-1 Dunquin deepwater exploration well was plugged and abandoned in the third quarter of 2013. The well did not encounter any significant hydrocarbon accumulations.

 

Italy 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 2013, 60 LNG cargoes were delivered, providing 3.6 million tonnes of LNG to the Italian natural gas grid.   Netherlands 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 2 billion cubic feet of gas in 2013. The majority of this production comes from the Groningen field (ExxonMobil interest, 30 percent), which is Europe’s largest natural gas field. In 2013, NAM continued to progress the Underground Storage Expansion project at Norg, which will help to sustain peak Groningen gas deliveries. NAM also started up a nitrogen injection project to enhance gas recovery from the De Wijk field. This first-ever commercial application of nitrogen injection solely for methane recovery will extend the life of this field, which has been producing for more than 50 years.		The West Alpha Rig, in Norway, commenced drilling at Balder in February 2013.

Norway

ExxonMobil is among the largest oil and gas producers in Norway, with average net production of 161 thousand barrels of liquids per day and 495 million cubic feet of gas per day in 2013. We operate offshore producing fields in Norway, including Ringhorne (ExxonMobil interest, 100 percent), Ringhorne East (ExxonMobil interest, 77 percent), and Balder (ExxonMobil interest, 100 percent). In 2013, production averaged 44 thousand oil-equivalent barrels per day for Balder and Ringhorne combined.

Drilling at Balder resumed in 2013 following the interpretation of a recent seismic survey in the Balder/Ringhorne area, and will continue into 2014. We are assessing the potential for further drilling at Ringhorne in future years.

ExxonMobil also has significant equity participation in approximately 20 producing fields offshore Norway. In 2013, average net production from these fields yielded 114 thousand barrels of liquids per day and 478 million cubic feet of gas per day. There are active drilling programs in several core areas including successful exploration drilling at Grane, Aasgard, and Volve.

In 2013, ExxonMobil’s equity in Ormen Lange was reduced from 7.2 percent to 6.3 percent following an equity redetermination. At Grane, a decision was made to restart import gas injection for improved oil recovery.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

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. The pilot compressor was completed in 2013 and readied for final testing under load in a submerged test facility in 2014.

ExxonMobil holds two exploration licenses covering 398,000 net acres: Møre Vest (ExxonMobil operated; working interest, 35 percent) in the Møre Basin and Ygg High (ExxonMobil interest, 30 percent) in the deepwater outer Vøring Basin. A 2D seismic survey using new acquisition technology was acquired for the Møre Vest license in 2013. We continued to process the 3D seismic survey acquired in 2012 for the Ygg High license. 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.

 

 

Poland

In 2013, ExxonMobil permanently abandoned the 2011 Krupe-1 and

Siennica-1 shale gas wells and withdrew from its Poland licenses.

Romania

ExxonMobil has a 50-percent working interest in the deepwater Neptun

Deep block covering approximately 932,000 net acres in the Black Sea.

Acquisition of a 2,300-square-mile 3D seismic survey was completed in

2013 and the data is currently being evaluated. Resource appraisal and

concept selection activities are progressing in support of potential

development of the Domino discovery with additional exploration and

appraisal drilling anticipated in 2014. ExxonMobil expanded its position

in the Romanian Black Sea with an agreement to purchase the deepwater

portion of the Midia License, covering 53,000 net acres.

Turkey

In 2013, ExxonMobil exited the operated sub-blocks of Licenses 3921

Kastamonu and 3922 Samsun and the Petrobras-operated portion of

License 3922 Sinop.

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.

United Kingdom

ExxonMobil holds significant interest in more than 40 producing fields in the North Sea, principally through a joint venture with Shell. In 2013, average net production from these fields was 20 thousand barrels of liquids per day and 293 million cubic feet of gas per day.

Following drilling results in 2013, an alternate subsea satellite development is under consideration for the offshore Fram field (ExxonMobil interest, 68 percent).

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 2013, 52 LNG cargoes were delivered, providing more than 5.6 million tonnes of LNG.

In addition, ExxonMobil has interests in several North Sea hydrocarbon transportation and processing systems, including the SEGAL gas plant at St. Fergus where we maximize the extraction of natural gas liquids to provide feedstocks to our onshore ethylene plant in Fife, Scotland.

 

 

 

AFRICA

ExxonMobil is one of Africa’s leading oil producers. Our operations in Africa accounted for 11 percent of our 2013 net oil and natural gas production and 17 percent of total Upstream earnings. In addition to producing activities, we have ongoing exploration activities. ExxonMobil holds interests in 19 deepwater blocks offshore Africa totaling approximately 11 million net acres.

Angola

We have interests in three deepwater blocks covering nearly 2 million acres in Angola. These world-class development opportunities have a gross recoverable resource potential of approximately 11 billion oil-equivalent barrels. Including production from the co-venturer-operated Block 17, our net production in Angola averaged 123 thousand barrels of oil per day in 2013. Several new projects are under construction or in development planning.

Block 15 • ExxonMobil has a 40-percent interest in Block 15. We have discovered total resources of approximately 5 billion gross oil-equivalent barrels on the block. With daily output of

more than 370 thousand barrels of oil, Block 15 was Angola’s

second-highest-producing block in 2013, and facilities continue to operate with very high levels of reliability.

Block 15 development now focuses on the Kizomba Satellites Phase 2 project, which includes subsea tiebacks to the Kizomba B and Mondo floating production, storage, and offloading (FPSO) vessels. The Phase 2 project is expected to recover nearly 190 million barrels of oil. Production is anticipated to start in 2015. Through collaborative development efforts with our partners and major contractors, 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 2013, 15 discoveries have been made on the block with a gross recoverable resource potential of approximately 5 billion oil-equivalent barrels. During 2013, production averaged more than 590 thousand barrels of oil per day from the Girassol, Dalia, Rosa, and Pazflor projects.

 

AFRICA HIGHLIGHTS		2013				2012				2011
Earnings (billions of dollars)			4.5				7.2				5.4
Proved Reserves (BOEB)			1.5				1.7				1.8
Acreage (gross acres, million)			23.0				14.1				15.1
Net Liquids Production (MBD)			0.5				0.5				0.5
Net Gas Available for Sale (BCFD)			–				–				–
Africa Production   (millions of oil-equivalent barrels per day, net)

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

 

Project execution activities continued for the Cravo- Lirio-Orquidea-Violeta (CLOV) project. CLOV is located in 4,100 feet of water and will use a new FPSO vessel to produce 160 thousand barrels of oil per day. The FPSO vessel arrived in Angola in 2013 and is expected to start production in 2014.   Also within Block 17, front-end engineering and design activities are under way for the Pazflor Satellites project, a subsea tieback to the Pazflor FPSO vessel. The project is expected to start production in 2017.   Block 32 • Development planning activities continue for Block 32 where ExxonMobil owns a 15-percent interest. Through year-end 2013, 12 discoveries have been announced with a total 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, which is progressing toward a full-funding decision in 2014, with estimated recovery of about 600 million barrels of oil. The water depths on this block range from 4,900 to 8,200 feet.		Angola Block 15 facilities, including the asset at Kizomba B, continue to operate with very high reliability.

Block 32 co-venturers were granted an exploration license extension in 2013, and exploration activities resumed with acquisition of a 3D seismic survey starting in November 2013. Seismic data acquisition will continue into 2014, when exploration drilling is planned to resume.

Chad

ExxonMobil is Chad’s leading oil producer (ExxonMobil interest, 40 percent) with average net production of 29 thousand barrels of oil per day in 2013. We celebrated the 10th anniversary of our operations in Chad in 2013 and continue an active two-rig development drilling program focused on the Kome, Bolobo, and Miandoum fields. ExxonMobil continues to support Chad resource development, and in late 2013, facilitated the start of crude shipment by other producers through our existing dedicated Chad-Cameroon pipeline to available markets.

Equatorial Guinea

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 965 million barrels in its 17 years of production. In 2013, net production averaged 34 thousand barrels of oil per day. A drilling and wellwork campaign began in 2013 and will continue through 2014.

Gabon

ExxonMobil acquired a 30-percent interest in the Arouwe Block offshore Gabon in 2013. A well is planned in this deepwater block in 2014.

Liberia

In 2013, ExxonMobil acquired an 83-percent interest in deepwater Liberia Block 13, covering approximately 520,000 net acres offshore Liberia’s central coast. Assessment of the block’s resource potential is under way, with future drilling planned.

Libya

ExxonMobil has been under force majeure since March 2011 in Contract Areas 20 and 21. In accordance with contractual terms, these Exploration and Production Sharing Agreements terminated in March 2013.

Madagascar

ExxonMobil holds an interest in more than 9.3 million net acres in the Majunga Basin offshore Madagascar. Extensions to the Production Sharing Contracts were ratified in 2013, and exploration activity resumed in Madagascar with 2D seismic data acquisition.

 

 

 

Nigeria

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) as well as 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 2013, net production in Nigeria averaged 285 thousand barrels of liquids per day.

Nigeria – Deepwater

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), which was fully funded in 2013, 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) contracts have been executed. Start-up is targeted for 2016.

Bonga North • The Bonga North development (ExxonMobil interest, 20 percent) is planned as multiple subsea wells tied back to an FPSO vessel. Early engineering and design continue, with the revised concept expected to develop more than 500 million oil-equivalent barrels.

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. Start-up is targeted for 2014.

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 approximately 800 million oil-equivalent barrels. Early procurement and contracting activities are under way.

Bosi • (ExxonMobil interest, 56 percent) is planned as a spread-moored FPSO vessel with associated subsea developments. The Bosi Phase 1 project is expected to develop more than 600 million barrels of oil. Project concept selection activities are progressing in participation with the Nigerian government and co-venture partner Shell Oil.

 

				OPL 214 • ExxonMobil was awarded operatorship of OPL 214 in 2001 (ExxonMobil interest, 20 percent) and discovered the Uge field in 2005. Development planning for Uge continues.   OPL 223 / OML 138 / OML 139 • Following the Owowo West discovery in 2012, we have continued to evaluate the potential of this deepwater region. A wildcat well on OML 138 (ExxonMobil interest, 30 percent) spud in December 2013. We are planning additional wells on OPL 223 (ExxonMobil interest, 27 percent) and OML 138 to further assess this area.   The Shelf Baltic drilling rig, offshore Nigeria, supported 2013 joint venture activities.

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

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 more than 300 million barrels of oil using subsea wells connected to a 180-thousand-barrel-per-day capacity FPSO vessel. ExxonMobil plans to assume operatorship of this asset in early 2014.

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, exploration activities continue in an effort to identify new opportunities within the joint venture. ExxonMobil discovered oil in an exploration well in early 2013 in OML 68 (ExxonMobil interest, 40 percent), and commercial viability and prospectivity are being evaluated.

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, with drilling continuing into 2014. 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, with early design of four new wellhead platforms and associated interconnecting pipelines.

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 36 thousand barrels per day in 2013. The projects are expected to recover approximately 400 million barrels of natural gas liquids. In addition, they have contributed to a 50-percent reduction in flaring since 2007.

Domestic Power Generation and Natural Gas Supply • Development of a nominal 530-megawatt power plant is under way. Engineering, procurement, and construction contract awards have been advanced for governmental approval. The plant is a central component of an integrated plan to increase gas utilization and power generation capacity in Nigeria.

Republic of Congo

Throughout the license period, 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. We continue to evaluate development options.

South Africa

In 2013, the government of South Africa approved ExxonMobil acquiring a 75-percent interest in the Tugela South Exploration Right. Future exploration rights in three offshore areas, and ExxonMobil’s 75-percent interest in them, remain subject to South

				African governmental approval. Additionally, ExxonMobil completed the study of the hydrocarbon potential of the Deepwater Durban Basin pursuant to a technical cooperation permit with the government, and submitted an application for an exploration right with 100-percent interest.   Tanzania After the three discoveries in 2012 on Block 2 (ExxonMobil interest, 35 percent), two additional wells were drilled in 2013. Tangawizi-1 was drilled in early 2013, which resulted in a 4-trillion to 6-trillion-cubic-foot natural gas discovery. A second discovery was made with the drilling of the Mronge-1 well, where an additional 2 trillion to 3 trillion cubic feet of natural gas was discovered, bringing the total discovered resource to 17 trillion to 20 trillion cubic feet of natural gas in place. 3D seismic data acquisition was completed in early 2013, and this data is being assessed to identify future prospects. Additional drilling is planned to further assess the potential of the block. Development planning, onshore site selection, and commercial discussions regarding a potential joint LNG plant with adjoining blocks were initiated in 2013.

 

 

 

ASIA   In Asia, ExxonMobil is participating in the development of some of the world’s largest oil and gas projects. Overall, ExxonMobil’s Asian operations accounted for 36 percent of our net oil and gas production and 48 percent of Upstream earnings.   Azerbaijan The Azeri-Chirag-Gunashli (ACG) megafield (ExxonMobil interest, 8 percent) has produced 2.4 billion barrels of oil since its 1997 start-up. In 2013, ACG production averaged 655 thousand barrels of oil per day. A sixth producing platform was installed in 2013, which will contribute an additional 185 thousand barrels per day to existing facility capacity. Start-up is planned for early 2014.		ASIA HIGHLIGHTS		2013				2012				2011
		Earnings (billions of dollars)			13.0				12.7				13.4
		Proved Reserves (BOEB)			7.9				7.7				8.1
		Acreage (gross acres, million)			60.3				31.5				31.0
		Net Liquids Production (MBD)			0.8				0.8				0.8
		Net Gas Available for Sale (BCFD)			4.3				4.5				5.0
		Asia Production   (millions of oil-equivalent barrels per day, net)

China

In July 2013, ExxonMobil signed a Joint Study Agreement covering 946,000 net acres in the Ordos Basin. We are working with PetroChina to evaluate the unconventional gas potential within the study area.

Indonesia

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 2013, net production from these fields averaged 110 million cubic feet of gas per day and 1 thousand barrels of associated liquids per day.

 

 

		EXXONMOBIL    2013 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations, continued

 

We also have active operations in the Cepu Contract Area, onshore Java (ExxonMobil interest, 45 percent). In 2013, we continued to increase production from the Banyu Urip early production facility, which was producing 29 thousand barrels per day at year end. The 165 thousand-barrel-per-day 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 off the coast of East Java. In 2013, we progressed the central processing facility construction activities, nearly completed onshore pipeline construction, commenced offshore pipelay and mooring tower construction, and progressed the FSO vessel refurbishment. Development well drilling is under way with two rigs in parallel operations.   Progress also continued on the Cepu Gas project, a unitized development covering the Jambaran and Tiung Biru gas fields with		The Banyu Urip development will have a capacity of 165 thousand barrels of oil per day.

PT Pertamina EP Cepu as the unit operator. Key milestones in 2013 included the completion of engineering optimization studies, awarding of process license contracts, and commencement of environmental impact assessments. The project is preparing for tendering for front-end engineering design contracts.

In December 2013, our Indonesian affiliate, Esso Natuna Ltd., signed a Fourth 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.

During 2013, ExxonMobil exited the deepwater Cendrawasih block offshore West Papua and initiated the exit process for the deepwater Surumana and Mandar blocks and the onshore Java Gunting block.

Iraq

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, 25 percent). In 2013, we sold a partial interest, reducing our interest from 60 percent to 25 percent. Located in one of Iraq’s most prolific producing areas, West Qurna I field redevelopment and expansion will entail infill drilling, reservoir pressure support, development of undeveloped reservoirs, new production facilities, and associated support infrastructure.

In 2013, we continued with redevelopment activities and the finalization of long-term development plans. Seismic data acquisition was completed and water injection activities are under way. Production capacity from West Qurna I reached 500 thousand barrels per day in 2013.

In October 2011, ExxonMobil signed six Production Sharing Contracts covering more than 848,000 acres in the Kurdistan Region of Iraq. ExxonMobil began a 2D seismic data acquisition program across four of our six blocks in 2013. Additionally, drilling operations began with the spud of the first ExxonMobil-operated well. Seismic and drilling operations will continue in 2014 to meet our license obligations.

Kazakhstan

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, the nearby Korolev field, and an associated processing complex. The Tengiz field has produced more than 2.2 billion barrels of oil from a total gross resource of approximately 6 billion barrels. Front-end engineering progressed and early works were initiated in 2013 for two projects to increase production capacity 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