Exhibit 99

 

 

Financial & Operating Review
2014
ExxonMobil
Energy lives here ™

 

 

 

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

Definitions of “resources” and “resource base,” as well as certain financial and operating measures and other terms used in this report are contained in the section titled “Frequently Used Terms” on pages 90 through 93. In the case of financial measures, such as “Return on Average Capital Employed” and “Free Cash Flow,” the definitions also include information required by SEC Regulation G.

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

Prior years’ data have been reclassified in certain cases to conform to the 2014 presentation basis.

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.

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2014: Financial & Operating Summary

 

 

ExxonMobil’s strategies are designed to deliver success. Our 2014 results once again demonstrate the strength of our integrated model and the benefit of our sound business approach. Our underlying financial strength remains a source of confidence in this period of rapid change in the energy markets. We continue to progress a unique and balanced set of attractive opportunities, which positions 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			27,548				164,965				16.7				32,727
Downstream			3,045				23,977				12.7				3,034
Chemical			4,315				22,197				19.4				2,741
Corporate and Financing			(2,388	)			(8,029	)			N.A.				35
Total			32,520				203,110				16.2				38,537

Operating Highlights

 

Liquids production (net, thousands of barrels per day)			2,111
Natural gas production available for sale (net, millions of cubic feet per day)			11,145
Oil-equivalent production(2) (net, thousands of oil-equivalent barrels per day)			3,969
Refinery throughput (thousands of barrels per day)			4,476
Petroleum product sales (thousands of barrels per day)			5,875
Chemical prime product sales(1) (thousands of tonnes)			24,235

 

32nd Consecutive Year of Dividend Growth(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 1982 Exxon dividend.

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

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

2 EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW
2014 Financial & Operating Summary
Results & Highlights
Strong environmental results and best-ever safety performance supported by effective risk management
Earnings of $32.5 billion and industry-leading return on average capital employed(1) of 16.2 percent
Capital and exploration expenditures(1) of $38.5 billion
Free cash flow(1) of $17.9 billion, up $7.3 billion compared to 2013
Dividends per share increased 9.5 percent in the second quarter of 2014, the 32nd consecutive year of dividend-per-share increases
Total shareholder distributions(1) of $23.6 billion
Proved oil and natural gas reserves(1) additions of 1.5 billion oil-equivalent barrels, replacing more than 100 percent of production for the 21st consecutive year
Completed eight major Upstream projects with working interest production capacity of more than 250 thousand oil-equivalent barrels per day, highlighted by the Papua New Guinea Liquefied Natural Gas project
Began construction of a world-scale steam cracker at our integrated complex in Baytown, Texas, to capitalize on abundant supplies of American natural gas liquids
Investing in a new delayed coker unit at our refinery in Antwerp, Belgium, to convert lower-value bunker fuel oil into higher-value diesel products
Successfully drilled the first ExxonMobil-Rosneft Joint Venture Kara Sea exploration well in the Russian Arctic
Exploration discoveries totaling 2.7 billion oil-equivalent barrels
Functional Earnings and Net Income
Upstream Downstream Chemical Corporate and Financing Net Income(2)
(billions of dollars)
50 40 30 20 10 0 -3
2010 2011 2012 2013 2014
Return on Average Capital Employed(1)(3)
2014 2010-2014 average
(percent)
25 20 15 10 5 0
ExxonMobil Chevron Shell Total BP
(1) See Frequently Used Terms on pages 90 through 93.
(2) Net income attributable to ExxonMobil.
(3) Competitor data estimated on a consistent basis with ExxonMobil and based on public information.

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Creating Value Through the Cycle

 

 

ExxonMobil is dedicated to generating long-term shareholder value. We recognize the nature and risk of the commodities we produce and have positioned our businesses to be successful throughout the business cycle. Our success is derived from our operational excellence, project execution capabilities, and proprietary technologies, underpinned by strong financial flexibility, investment discipline, and a world-class workforce.

Operational Excellence Ensuring the safety and reliability of our operations is fundamental to our business success and a critical challenge that ExxonMobil takes on every day. In 2014, we achieved our best-ever safety performance. We maintain an unwavering commitment to achieve our vision that Nobody Gets Hurt.

Upstream Over the past year, we successfully advanced resource development focused on adding higher-margin production. Eight major projects were completed, including Papua New Guinea Liquefied Natural Gas which underscored ExxonMobil’s project execution expertise. Other successful projects included Arkutun-Dagi in Russia; Cold Lake Nabiye Expansion in Canada; Lucius in the Gulf of Mexico; and Cravo-Lirio-Orquidea-Violeta (CLOV) in Angola. In the United States, we are increasing development activities to grow higher-margin liquids production across the Permian, the Bakken, and the Ardmore/Marietta plays. We remain on target to grow total production to 4.3 million oil-equivalent barrels per day by 2017.

 

Downstream and Chemical We continue to capture significant benefits by driving operational efficiencies, diversifying feedstocks through our flexible and integrated system, expanding logistics capabilities, and maximizing sales of higher-value lubricant, diesel, and chemical products. Our capacity to process lower-cost ethane into ethylene already leads the industry in the United States and we are growing that leadership position with the expansion of our site in Baytown, Texas, and the construction of two premium polyethylene lines at the nearby Mont Belvieu Plastics Plant. In Saudi Arabia, we commissioned a project to reduce sulfur levels in gasoline and diesel at the refinery in Yanbu, and we are working with our joint venture partner, Saudi Basic Industries Corporation, to expand the range of chemical specialty products manufactured in the region. In Antwerp, Belgium, at our largest and most efficient refinery in Europe, we started construction to install a delayed coker that will help meet growing demand for cleaner transportation fuels.   The success of our integrated business is achieved by connecting the strengths of each of our individual businesses through our organization structure, systems, and work processes. The results allow us to maximize the value of every molecule we produce, refine, or manufacture. Strategic decisions across our business segments are based on a long-term view and a commitment to effective risk management. We anticipate, plan for, and mitigate geopolitical risks and uncertainty throughout our broad, diversified global portfolio. Most importantly, we have unmatched optionality to selectively invest in only the most attractive resource development projects, enabling us to generate long-term shareholder value through the cycle.   Rex W. Tillerson, Chairman and CEO

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C R E A T I N G    V A L U E    T H R O U G H    T H E    C Y C L E

Operational Excellence

 

 

Our goal is to retain employees for the long term so they can grow professionally, contribute to our strong experience base, and develop into our next generation of global leaders. Employees receive diverse experiences and assignments enabled by our global functional organization, which encourages the sharing of information and talent. This philosophy extends to local workforce development, where we hire and train people from the countries in which we operate.

 

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Our Commitment to Safety, Security, Health, and the Environment

ExxonMobil’s Operations Integrity Management System (OIMS) is a cornerstone of our commitment to managing safety, security, health, and environmental risks, and achieving excellence in performance. The OIMS framework establishes common worldwide expectations for managing risks inherent to our business and addresses all aspects that can impact personnel and process safety, security, health, and environmental performance. The focus on process safety protects our workforce, our equipment and assets, the local environment, and the communities in which we operate.

OIMS provides the structure to help us meet or exceed applicable regulations and relevant industry standards. 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. As we manage the safety, security, health, and environmental risks in our business, we focus our efforts on understanding the root cause and potential consequence of each injury, spill, or process safety event. We assess the facilities and effectiveness of our procedures, personnel training, and execution discipline to gain insight from actual, near-miss, or potential events, then share the

learnings across our businesses. Through analysis of past or potential events, including industry events, the aim is to prevent incidents.
Risk Management
We take a systematic approach to risk management, guided by OIMS. Every activity contains some element of risk – whether technical, operational, procedural, financial, or environmental. We each take responsibility to identify the elements of risk inherent in all our endeavors. We look to understand the consequences

associated with these risks and find solutions that would eliminate, mitigate, or manage the risk to an acceptable level. Through the use of appropriate protective measures and safeguards, the likelihood or severity of an undesirable event can be reduced.

Our thoughtful change management approach enables us to effectively identify, plan for, and mitigate changed conditions and risks along with their potential consequences throughout our operations. As a result, management of change is a key component of our OIMS framework. Our approach to risk management is supported by well-developed and clearly defined policies and procedures to ensure that we have a structured, globally consistent system with the highest standards in place.

 

Highlight: OIMS Execution

At ExxonMobil, we look to ensure effective safeguards are intact.

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C R E A T I N G    V A L U E    T H R O U G H    T H E    C Y C L E

Upstream: Demonstrating Project Execution Capabilities

 

 

ExxonMobil is building upon its 115-year history in Indonesia by progressing completion of the world-class Banyu Urip project, the country’s largest new oil development. At a cost of more than $3 billion, the project will deliver substantial liquids production while providing multiple benefits to Indonesia and its people.

 

To limit its environmental footprint, the project’s 48 wells are drilled from only three well pads. Produced oil, water, and gas are processed at a central processing facility. Crude oil then flows through 60 miles of onshore and offshore pipelines to an offshore mooring tower that connects to a floating storage and offloading (FSO) vessel, which can store up to 2.2 million barrels of oil.

The mooring tower, anchored into the seabed in about 100 feet of water, has a large swiveling assembly to enable the vessel to rotate freely with shifting winds, waves, and currents without disrupting the flow of oil coming from the pipeline.

Construction of the pipelines, mooring tower, and vessel is complete, and over 90 percent of the project facilities have been installed. The drilling program is progressing ahead of schedule and facilities commissioning is under way.

Safety of our workforce has been a primary focus during project execution. The team has achieved outstanding safety performance and has been recognized with multiple industry awards.

 

 

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Production Ramp-Up   While the full field development was being progressed, ExxonMobil installed facilities to bring early oil production to local markets. First oil from the Banyu Urip field was produced in 2008. An early production facility started up in 2009 with an initial production capacity of 20 thousand barrels of oil per day. As new wells were brought online, production increased to more than 40 thousand barrels per day. Total oil production will continue to ramp up until it reaches full field capacity in 2015.		Once fully commissioned, the Banyu Urip facilities are anticipated to produce up to 165 thousand barrels of oil per day at peak capacity.

From Indonesia, for Indonesia

The Banyu Urip project has focused on developing the skills and knowledge base of Indonesian nationals through training and use of local contractors and suppliers. During project execution, 460 national companies supported the EPC consortiums as subcontractors, with 85 percent originating from areas neighboring the project facilities. At its peak, over 10,000 Indonesian workers were involved in the construction of facilities, with thousands coming from communities in the immediate surroundings. Overall, ExxonMobil delivered 2 million training hours to Indonesian workers through 2,500 courses.

Increasing Indonesia’s industrial capability has been a key focus area for the project team. The mooring tower and support structures, at a combined weight of over 3,800 tonnes, were fabricated on Java Island. Two 1,500-horsepower drilling rigs, the first ever constructed entirely in Indonesia, are being used to drill project wells. The positive legacy of Banyu Urip’s construction will live on through the workers who continue to benefit from our training and mentoring programs.

The project’s impact will continue into the operations of the facilities and last for decades. More than 100 operations and maintenance technicians are being trained to operate the facilities during the production phase. Some have completed on-the-job training at ExxonMobil operations in Angola, Cameroon, Malaysia, Nigeria, and the United States. These Indonesian employees have returned home following the completion of their overseas assignments to run the Banyu Urip operations.

Being a Great Neighbor

ExxonMobil has invested in various community programs in East Java. More than 70,000 community members have benefited from our programs focused on education, health, and economic development. From teacher training (3,000 trained, serving 33,000 students) and educational assistance, to clean water and biogas supplies, to micro-loans for local citizens to begin new businesses, the Banyu Urip project has contributed greatly to the local communities.

The project will also provide substantial economic benefits to the country. The total investment of more than $3 billion is expected to generate $30 billion in revenue for the Government of Indonesia.

Overall, the Banyu Urip project is making a significant positive impact in Indonesia, both as the nation’s largest new oil project, and as a key driver of economic growth and community enhancement.

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C R E A T I N G    V A L U E    T H R O U G H    T H E    C Y C L E

Upstream: Unlocking Resource Value

 

 

Driven by a strong acreage position and operational expertise in unconventional plays, ExxonMobil has emerged as the leading oil and gas producer in the United States. With support from our world-class research organization and Downstream businesses, our XTO organization is significantly growing production volume from liquids-rich plays in the Permian, Bakken, and Ardmore/Marietta.

Permian: Expanding Horizontal Upside

 

production in our Fullerton and Robertson fields has more than doubled over the past three years to more than 10 thousand barrels per day, as a result of an aggressive workover and infill drilling program in the main Clearfork reservoir.

We continue to expand production capacity by progressing water and gas-handling improvement initiatives. Through third-party agreements, we recently completed gas gathering and plant projects in the Goldsmith and Parks Pegasus areas, allowing for more efficient processing of associated gas, improved uptime, reduced flaring, and higher yield.

We also expanded our acreage position during 2014 through three transactions that roughly doubled our leasehold acreage to 130,000 acres in the core of the Wolfcamp play in the Midland Basin. The transactions highlight our disciplined investment approach and unique ability to execute deals with attractive valuations in a competitive industry environment.

In 2014, 16 horizontal Wolfcamp wells were brought online with encouraging initial production as we continue to optimize drilling and completions, and further delineate acreage. The application of horizontal drilling, combined with hydraulic

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Bakken: Liquids Growth Engine   In the Bakken, net production increased 38 percent in 2014, due to a record 144 wells brought to sales, improved well productivity, and accelerated pad development in our core acreage. Production has increased sixfold since our 2008 entry into the play. We were operating 16 rigs at year end, up 45 percent from the prior year. Natural gas sales are also growing, while gas flaring is being reduced with additional industry infrastructure and field modifications.   Our operating efficiency is improving in the Bakken. We continually adjust our drilling and completion practices to reduce costs, and have experienced a 34-percent decline in per-well drilling days since 2011. The ExxonMobil proprietary XFrac completion technology, now piloted in more than 20 wells, will potentially enable further cost reductions as it significantly reduces the number of plugs between fracture stimulation stages deep in the well.				Production from the Bakken increased almost 40 percent in 2014 through a record 144 wells to sales.

Ardmore/Marietta: Entering the Development Phase

In southern Oklahoma, net production from our Ardmore/Marietta liquids-rich plays increased 30 percent in 2014, attributable mainly to higher activity as we brought 89 wells to sales. Ten operated rigs were utilized across our leasehold of more than 225,000 net acres.

In the Ardmore area, focus has turned to developing the core Woodford Shale acreage and optimizing spacing while we continue to delineate the overlying Caney Shale. Similar to our other unconventional plays, we are capturing substantial operating efficiencies in the Ardmore as drilling days per well have decreased by 46 percent since 2009 to roughly 33 days. In the Marietta area, which features a higher proportion of oil production, we commenced delineation of our leasehold in 2014 by bringing 12 wells to sales.

 

Following the success of field trials in Fayetteville, ExxonMobil’s Drilling Advisory System tool was deployed to support operations in the Ardmore Basin in 2014. It seamlessly integrates with existing drilling rig systems to promote consistent application of ExxonMobil’s Fast Drill process, with cost savings derived from improved drilling efficiency and performance.   CO2 injection from the Means Compressor Station is used to enhance oil recovery in the Permian Basin.

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C R E A T I N G    V A L U E    T H R O U G H    T H E    C Y C L E

Downstream: Strengthening the Portfolio

 

 

ExxonMobil’s Downstream investments continue to strengthen our advantaged assets by increasing high-value product yields, improving feedstock flexibility, expanding logistics capability, and increasing operating efficiency. We carefully evaluate investment opportunities across a wide range of market conditions and only advance projects generating long-term shareholder value. The success of our disciplined investment approach and the strength of our integrated model underpin our ability to outperform competition across the cycle.

Increasing Higher-Value Product Yields

 

Despite challenging market conditions, we have some of the largest, lowest-cost refineries in Western Europe which benefit from fuels, lubes, and chemical integration. Building on our competitive cost position at our Antwerp Refinery, construction of a 50-thousand-barrel-per-day delayed coker began in 2014. Scheduled to start up in 2017, the new facility will help meet growing demand for cleaner transportation fuel by converting lower-value fuel oil into higher-value

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Improving Feedstock Flexibility and Expanding Logistics Capability

We employ advantaged technologies to increase the flexibility of our facilities, allowing us to process the lowest-cost feedstocks available and increase margins. ExxonMobil has the largest combined mid-continent and Gulf Coast refining capacity in the industry, allowing our refineries to benefit

from the growing North American crude oil supply. Investments continue to expand refinery flexibility. For example, we recently completed a metallurgy upgrade project at our refinery in Beaumont, Texas, expanding heavy Canadian crude processing capacity. We are also expanding capability to run higher-sulfur crudes in Baton Rouge, Louisiana.   In North America, we are also investing to strengthen our crude oil and product logistics capabilities. For example, along with Kinder Morgan Canada Terminals, we are investing in a joint venture rail terminal in Edmonton to provide cost-advantaged export logistics for the growing supply of Western Canada crude oil. The new terminal will begin operating in 2015 with a capacity of 210 thousand barrels per day. Additional investments are also under way to expand product logistics capabilities at our large U.S. Gulf Coast refineries.				ExxonMobil North America Domestic Crude Processing(1)   (percent)     A recent success has been the introduction of price-advantaged U.S. tight oil and Canadian heavy oil crudes, allowing us to reduce imported crudes.

World-Class Operating Efficiency

Underpinned by disciplined investments and ongoing efforts to capture efficiencies, worldwide cash operating cost for our portfolio of refineries has consistently been well below the industry average. As examples, our Baton Rouge and Antwerp Refineries are among the lowest-cost refineries in the United States and Western Europe, respectively. With energy representing as much as 60 percent of the operating cost of a refinery, we continue to expand our leadership position in cogeneration capacity to capture additional efficiencies.

 

Portfolio Optimization   Disciplined capital management includes continuous assessment and optimization of our asset portfolio. Since 2005, we have reduced our refining capacity by more than 1 million barrels per day by divesting or restructuring 23 less-competitive facilities. The refineries that remain in our portfolio are generally larger, more efficient, and integrated with chemical and lubricant manufacturing facilities. We have also divested or restructured more than 6,000 miles of pipeline, over 200 fuel terminals, 38 lubricant plants, and in excess of 15,000 retail service stations. These portfolio optimizations improve our Downstream return on average capital employed and support our ability to outperform competition across the cycle.				Downstream Return on Average Capital Employed(2)     (1) Mid-continent and U.S. Gulf Coast refineries. (2) See Frequently Used Terms on pages 90 through 93. (3) BP, Chevron, Royal Dutch Shell, and Total values are estimated on a consistent basis with ExxonMobil and are based on public information.

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C R E A T I N G    V A L U E    T H R O U G H    T H E    C Y C L E

Chemical: Progressing Strategic Investments

 

 

Our Chemical business is well positioned to capture market growth opportunities by developing world-scale assets that utilize proprietary technologies to capture advantaged feedstocks, deploy lower-cost processes, and increase premium product sales. Our strategic and disciplined investment approach delivers superior returns throughout the business cycle and across a variety of market conditions.

United States

 

Singapore

At our Singapore petrochemical hub, we have started a project to add production of halobutyl rubber and premium resins for adhesive applications. These facilities will be the largest units we have ever built for these polymers. The project will

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Saudi Arabia   We are working with our joint venture partner, Saudi Basic Industries Corporation, to build a first-of-its-kind specialty elastomers facility in Saudi Arabia. With start-up anticipated in 2015, the project will help meet the growing demand for synthetic rubber-based automotive products.   We are integrating proprietary ExxonMobil technologies for premium halobutyl and ethylene propylene diene monomer (EPDM) rubbers into the existing joint venture operations at Al-Jubail. These ExxonMobil processes enable lower-cost production. For example, our proprietary halobutyl configuration and equipment design save energy and capital investment per tonne of capacity. Similarly, our metallocene EPDM technology utilizes fewer process steps and consumes less energy while significantly reducing emissions.   This project builds on our existing world-scale commodity assets at the site, which benefits from low-cost feedstocks.   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. The success of this approach is demonstrated by our ability to deliver superior returns on average capital employed relative to competitors throughout the business cycle. Investments under development will continue to support this industry-leading position.				In 2014, we progressed construction on facilities in Al-Jubail, Saudi Arabia, that will produce a broad range of synthetic rubber and related products.

Chemical: Industry-Leading Returns⁽¹⁾

(10-year average, 2005–2014)

 

Revenue   (billions of dollars)		Earnings   (billions of dollars)		Return on Average Capital Employed (2)   (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 2013.

14 EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW
Cold Lake, Canada Joliet, United States Rotterdam, Netherlands
Global Operations
As the world’s largest publicly held oil and gas company, ExxonMobil has a diverse and balanced portfolio of high-quality resources, projects, and assets across our Upstream, Downstream, and Chemical businesses.
Upstream Our Upstream business encompasses
high-quality exploration opportunities across all resource types and geographies, an industry-leading resource base, a portfolio of world-class projects, and a diverse set of profitable producing assets. We have an active exploration or production presence in 36 countries.
Downstream Our balanced Downstream portfolio includes refining facilities in 17 countries. We are one of the world’s largest integrated refiners and manufacturers of lube basestocks, and a leading marketer of petroleum products and finished lubricants. Our high-quality products, combined with a strong global refining and distribution network, position us as a premier supplier around the world.
Chemical ExxonMobil Chemical is one of the largest chemical companies in the world.
Our unique portfolio of commodity and specialty businesses delivers superior returns across the business cycle. We manufacture high-quality chemical products in 16 countries. With a major presence in Asia Pacific, we are well positioned to competitively supply the rapid chemical demand growth in this region.

15
Al-Jubail, Saudi Arabia Tapis, Malaysia Altona, Australia
As of December 31, 2014

16 EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW
PHOTO: Construction of the 600-thousand-tonne concrete gravity-based structure for the Hebron platform in Newfoundland, Canada, is under way. Once complete, the structure will be nearly 400 feet tall and support a 65-thousand-tonne topside capable of producing 150 thousand barrels of oil per day when it starts up in 2017.

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Upstream
ExxonMobil’s Upstream encompasses high-quality exploration opportunities across all resource types and geographies, an industry-leading resource base, a portfolio of world-class projects, and a diverse set of profitable producing assets.
92billion
Oil-equivalent barrels of total resource base.

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EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW
Upstream

2014 Results & Highlights		Strategies
Achieved strong safety and operational performance Delivered industry-leading earnings of $27.5 billion and return on average capital employed of 16.7 percent Increased proved oil and natural gas reserves by 1.5 billion oil-equivalent barrels, replacing more than 100 percent of production for the 21st consecutive year Added 3.2 billion oil-equivalent barrels of new resource, increasing total resource base to more than 92 billion oil-equivalent barrels Discovered 2.7 billion oil-equivalent barrels through exploration drilling		Apply effective risk management, safety standards, and operational excellence Capture material and accretive resources to continually highgrade the portfolio of opportunities Exercise a disciplined approach to investing and cost management Develop and apply high-impact technologies Pursue productivity and efficiency gains to reduce cost Grow profitable oil and gas production Capitalize on growing natural gas and power markets
Completed eight major projects including the 6.9-million-tonnes-per-year Papua New Guinea Liquefied Natural Gas (LNG) project Initiated commissioning activities at the Kearl Expansion and Banyu Urip projects Successfully drilled the first ExxonMobil-Rosneft Joint Venture Kara Sea exploration well in the Russian Arctic Progressed a large and diverse portfolio of LNG opportunities by initiating early concept selection and engineering work on opportunities in North America, Australia, and Africa

Upstream Statistical Recap		2014		2013		2012		2011		2010
Earnings (millions of dollars)		27,548		26,841		29,895		34,439		24,097
Liquids production (net, thousands of barrels per day)		2,111		2,202		2,185		2,312		2,422
Natural gas production available for sale (net, millions of cubic feet per day)		11,145		11,836		12,322		13,162		12,148
Oil-equivalent production(1) (net, thousands of barrels per day)		3,969		4,175		4,239		4,506		4,447
Proved reserves replacement ratio(2)(3) (percent)		111		106		124		116		211
Resource additions(2) (millions of oil-equivalent barrels)		3,206		6,595		4,012		4,086		14,580
Average capital employed(2) (millions of dollars)		164,965		152,969		139,442		129,807		103,287
Return on average capital employed(2) (percent)		16.7		17.5		21.4		26.5		23.3
Capital and exploration expenditures(2) (millions of dollars)		32,727		38,231		36,084		33,091		27,319

(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.

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Business Overview

Our Upstream business includes exploration, development, production, natural gas marketing, and research activities.

ExxonMobil is driven to deliver industry-leading returns throughout the business cycle. We do this by capturing material and accretive opportunities to continually highgrade our resource portfolio. We seek to maintain a large, diverse, and balanced portfolio of opportunities to ensure selectivity and profitable growth through a wide range of investment and geopolitical environments. We create value through capital discipline by progressing only the most profitable opportunities. Proven project management systems incorporate best practices developed from our experience of rigorously managing a global project portfolio, from initial discovery phase to production start-up.

Technology is vital to meeting the growing global demand for oil and gas. We have a long-standing commitment to apply research and technology to efficiently find, develop, and produce resources from some of the most challenging reservoirs. We benefit from an integrated model, as technology advances in the Upstream, Downstream, and Chemical businesses can be used to address challenges across the company.

We focus on improving long-term profitability by investing in higher-margin barrels, maximizing production of installed capacity, and driving cost efficiencies through productivity and efficiency gains. When appropriate, we engage resource owners to develop mutually beneficial fiscal and contractual terms to promote resource development.

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

Business Environment

Over the coming decades, energy sources will continue to evolve and diversify, driven by changes in technology, consumer needs, and public policies. Crude oil is projected to remain the single biggest source of energy, while natural gas will play an increasingly important role in meeting global energy needs. Demand for oil is projected to rise by approximately 30 percent through 2040, led by increased commercial transportation activity. A growing share of this demand will be met by sources such as deep water, oil sands, and tight oil, as a result of advances in technology. Natural gas will be the fastest-growing major energy source through 2040. Global demand is projected to rise by close to 65 percent from 2010 to 2040 and gas supplies from unconventional sources are projected to account for about two-thirds of that growth. Liquefied natural gas volumes are expected to triple by 2040, contributing almost 20 percent of global gas supply.

Meeting the world’s growing demand for energy presents a tremendous challenge that requires a long-term view, significant investment, and continued innovation to develop conventional and unconventional resources. ExxonMobil is well positioned to meet this challenge.

 

Global Liquids Supply by Type				Global Natural Gas Supply by Type

Source: ExxonMobil, 2015 The Outlook for Energy: A View to 2040

20		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

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 rigorous approach throughout the asset life cycle, from initial resource capture and project execution to production operations. Our primary focus is to deliver superior investment returns over the long term.   Production Volumes   Net daily liquids production was up 44 thousand barrels or 2 percent versus 2013, excluding the impact of the United Arab Emirates onshore concession expiry, as the start-up of major projects, increased U.S. unconventional liquids production, and improved uptime performance more than offset field decline. Net natural gas production was down almost 6 percent due to lower weather-related demand and field decline, partly offset by project start-ups. Total net oil-equivalent production of 4.0 million barrels per day was essentially in line with our plans.   Near-term activity will focus on completing 16 projects in the 2015 to 2017 timeframe, highlighted by the Banyu Urip, Kearl Expansion, Gorgon Jansz, Kizomba Satellites Phase 2,

Highlight: Project Execution

Project Execution Performance

ExxonMobil Projects

(percent of plan, 2010-2014 average)

Cost

Schedule

ExxonMobil Operated

108

111

Operated by Others

110

135

PHOTO: The PNG LNG project started up in April 2014, several months ahead of schedule.

Upper Zakum 750, and Hebron projects. We plan to continue growing our large, liquids-rich North American unconventional resources with a focus on the Permian, Bakken, and Ardmore/Marietta areas. We will also continue to pursue attractive opportunities to increase volumes from existing assets through new drillwells, workovers of existing wells, and secondary and tertiary recovery programs.

 

Liquids production is anticipated to grow by 7 percent in 2015 and by 4 percent per year on average for 2016 and 2017. Natural gas production is anticipated to decline by 3 percent in 2015 and to grow by 1 percent per year on average for 2016 and 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.   Overall, higher-margin liquids and liquids-linked gas volumes are projected to grow to 71 percent of our total production, improving our total portfolio profitability mix.				Production Outlook(1)   (millions of oil-equivalent barrels per day, net)

(1) Excludes impact of future divestments and OPEC quota effects. Based on $55 Brent price.

		21

 

 

 

		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 (%)
		2012–2014 (Actual)																		2016–2017 (Projected) (continued)
		Angola		Cravo-Lirio-Orquidea-Violeta (CLOV)		160		-		20		l								U.S.		Heidelberg		80		80		9		l
				Kizomba Satellites Phase 1		100		-		40		n										Julia Phase 1		30		-		50		n
		Australia		Kipper-Tuna		15		175		40		n										Point Thomson Initial Production System		10		200		62		n
				Turrum		20		200		50		n
		Canada		Cold Lake Nabiye Expansion(2)		50		-		100		n								2018+ (Projected)
				Hibernia Southern Extension		55		-		27		n								Australia		Gorgon Area Expansion		10		915		25		l
				Kearl Initial Development		110		-		100		n										Scarborough		-		1,030		50		n
				Syncrude Aurora North Mine Sustaining Project		215		-		25		p								Canada		Aspen		90		-		100		n
																						Cold Lake Grand Rapids		40		-		100		n
				Syncrude Mildred Lake Mine Sustaining Project		180		-		25		p
																						Firebag		380		-		70		n
		Malaysia		Damar Gas		5		200		50		n										Steam-Assisted Gravity		445		-		63-100		n
				Telok		-		430		50		n										Drainage (SAGD)
																						Syncrude Aurora South		210		-		25		p
		Nigeria		Satellite Field Development		70		-		40		n										Phases 1 and 2
				Phase 1																		Syncrude Mildred Lake		210		-		25		p
				Usan		180		-		30		n										Extension
		Papua New Guinea		PNG LNG		30		1,000		33		n										West Coast Canada (WCC) LNG		-		1,600		100		n
		Russia		Sakhalin-1 Arkutun-Dagi(2)		90		-		30		n								Indonesia		Cepu Gas		5		180		41		l
		U.S.		Lucius(2)		100		150		23		l										Natuna(5)		-		1,100				n
		2015 (Projected)																		Iraq		West Qurna I		1,600		-		33		p
																				Kazakhstan		Kashagan Future Phases		1,260		-		17		l
		Angola		Kizomba Satellites Phase 2		85		-		40		n										Tengiz Expansion		655		-		25		l
		Canada		Kearl Expansion		110		-		100		n								Nigeria		Bonga North		200		-		20		l
		Indonesia		Banyu Urip		165		15		45		n										Bonga Southwest		200		-		16		l
		Nigeria		Erha North Phase 2		60		-		56		n										Bosi		140		315		56		n
		Norway		Aasgard Subsea Compression		40		415		14		l										Satellite Field Development Phase 2		80		-		40		n
		Qatar		Barzan		90		1,400		7		p										Uge		110		20		20		n
		U.S.		Hadrian South		5		300		47		n										Usan Future Phases		50		-		30		n
		2016–2017 (Projected)																		Romania		Domino		-		630		50		n
																				Russia		Sakhalin-1 Future Phases		-		800		30		n
		Angola		AB32 Kaombo Split Hub		250		-		15		l								Tanzania		Tanzania Block 2		-		1,000		35		l
		Australia		Gorgon Jansz(3)		20		2,765		25		l								U.S.		Alaska LNG		60		3,500		36		p
		Canada		Hebron		150		-		36		n										Golden Pass Products LNG Export		-		2,500		30		p
		Kazakhstan		Kashagan Phase 1(4)		370		450		17		l
		Russia		Sakhalin-1 Odoptu Stage 2		55		-		30		n										Julia Phase 2		30		-		50		n
		UAE		Upper Zakum 750		750		-		28		p								Vietnam		Ca Voi Xanh		3		375		64		n

 

(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. (2) Projects completed in 2014 with first production in early 2015. (3) Start-up target year-end 2015 with first ExxonMobil volumes in early 2016. (4) Operations were suspended in 2013. (5) Working interest pending final agreements.				KBD = Thousand barrels per day
				MCFD = Million cubic feet per day
				n ExxonMobil Operated
				l Co-Venturer Operated
				D Joint Operations

22		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

Global Upstream Portfolio, continued

 

 

 

Major Developments		Production Outlook from Major Developments
ExxonMobil participated in the completion of eight major projects in 2014, and we plan to bring 16 more projects to completion and start-up by year-end 2017. We generated significant volume growth from onshore U.S. liquids-rich plays across the Permian, Bakken, and Ardmore/Marietta areas.   Arkutun-Dagi ¡ (ExxonMobil interest, 30 percent) Arkutun- Dagi is the third field in the Sakhalin-1 development in Russia. Installation of the facilities was completed in 2014. Development drilling started in late 2014, with first production initiated in early January 2015. The project is anticipated to achieve peak production of 90 thousand barrels of oil per day in the coming years.   Cold Lake Nabiye Expansion ¡ (Combined ExxonMobil and Imperial Oil interest, 100 percent) Construction of the Nabiye expansion facilities in Canada was completed in 2014 and first steam injection into the reservoir commenced in early January 2015. Initial bitumen production is expected in the first quarter of 2015. Nabiye has a production capacity of 50 thousand barrels of bitumen per day.		Production by Start-Up Year (1)     (1) Excludes impact of future divestments and OPEC quota effects. Based on $55 Brent price. (2) Includes Bakken, Permian, and Ardmore/Marietta developments.   Over the 2012-2017 period, we anticipate adding close to 1 million net oil-equivalent barrels per day from major projects and an additional 150 thousand barrels per day from major developments in the Lower 48.

Damar ¡ (ExxonMobil interest, 50 percent) Damar first gas was achieved on schedule in January 2014. Located offshore Malaysia, the project includes the installation of a wellhead platform with a capacity of 200 million cubic feet per day and tie-in to existing facilities.

Hibernia South Extension ¡ (ExxonMobil interest, 27 percent) The Hibernia South Extension project offshore Canada started up in November 2014. The project included a subsea tieback to the existing Hibernia platform to provide water injection, platform modifications, and additional drillwells. The project is expected to develop 170 million barrels of oil and add 55 thousand barrels per day of production capacity.

Papua New Guinea Liquefied Natural Gas (PNG LNG) ¡ (ExxonMobil interest, 33 percent) The $19 billion PNG LNG project started up ahead of schedule in April 2014 and is currently producing at full capacity of 6.9 million tonnes per year. It is expected to produce more than 9 trillion cubic feet of gas during its estimated 30 years of operation.

U.S. Onshore ¡ More than 400 new wells were brought to sales mainly across the Permian, Bakken, and Ardmore/Marietta areas during 2014, resulting in 21-percent production growth relative to 2013. Our operating efficiency is continuing to improve, as demonstrated in the Bakken, where drilling days were reduced by 34 percent over the past four years.

 

		23

 

Upstream Opportunity Capture

 

 

Integration of technical expertise and industry-leading research capabilities enables ExxonMobil to identify and selectively capture the highest-quality resources across all 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.

2014 Opportunity Captures

In 2014, we captured 15 new opportunities spanning conventional and unconventional plays to build on our industry-leading resource base. At year-end 2014, our exploration acreage totaled more than 116 million net acres in 32 countries.

Argentina ¡ ExxonMobil expanded its interest in the Neuquén Basin by acquiring a 42.5-percent interest in the Parva Negra Este block, adding 30,000 net acres in the prospective Vaca Muerta unconventional play.

Brazil ¡ We grew our deepwater acreage position by acquiring a 35-percent stake in the POT-M-475 block in the Potiguar Basin, adding 66,000 net acres. ExxonMobil will operate this block.

Canada ¡ ExxonMobil was the high bidder on three blocks in the Newfoundland and Labrador lease sale held in December 2014, expanding our presence by 889,000 net acres in the Flemish Pass. The licenses were officially awarded in 2015 with ExxonMobil as the operator.

Côte d’Ivoire ¡ ExxonMobil entered Côte d’Ivoire by capturing 2.1 million net acres in two frontier deepwater blocks. ExxonMobil will operate these blocks.

Norway ¡ In February 2014, ExxonMobil was awarded a 50-percent interest in Block PL072D (Statoil operated) license round covering a portion of the Knappen prospect.

Papua New Guinea ¡ We successfully acquired an additional 10,500 net acres in the PNG Highlands trend.

Romania ¡ ExxonMobil acquired a 42.5-percent interest in the Midia Deep Black Sea block, capturing 53,000 net acres. ExxonMobil will operate the block along with its current operations to the southeast in the Neptun Deep block.

Russia ¡ ExxonMobil completed joint venture agreements with Rosneft for seven blocks in the Russian Arctic totaling 52.3 million net acres.

United Kingdom ¡ U.K.’s 28th offshore licensing round awarded two licenses consisting of 129,000 net acres in the North Sea to a partnership between ExxonMobil and Shell.

U.S. Offshore ¡ We added to our position in the Gulf of Mexico by a combined 30,000 net acres. We were awarded seven Outer Continental Shelf blocks in Sale 231, Sale 233, and Sale 238. In addition, we increased our share in the Lucius development to 23.3 percent.

U.S. Onshore ¡ In 2014, we added to our strong Permian leasehold through three strategic transactions, with 65,000 acres in the prolific Midland Basin, doubling our position to 130,000 acres.

 

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

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

24		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

Upstream Opportunity Capture, continued

 

 

Global Upstream Portfolio

 

 

Resources

In 2014, we continued to build our diverse global portfolio of resources and reserves by adding 3.2 billion oil-equivalent barrels. After adjusting for production, asset sales, and revisions to existing fields, the resource base totals more than 92 billion oil-equivalent barrels. Proved reserves comprise approximately 27 percent of the resource base, or 25 billion oil-equivalent barrels.

Our industry-leading record of long-term reserves replacement demonstrates the success of our global strategy to identify, evaluate, pursue, and capture high-quality opportunities. The size and diversity of ExxonMobil’s global resource base, the largest held by an international oil company, provide us with unequaled investment flexibility to profitably develop new supplies of energy to meet future demand.

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 2014, resources were added in Angola, Argentina, Australia, Canada, Nigeria, Norway, Tanzania, and the United States.

Our exploration drilling program added 2.7 billion oil-equivalent barrels in 2014, 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.

		25

 

 

 

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 oil and gas, and heavy oil/oil sands, which comprise 72 percent of the total. LNG and deep water account for about 13 percent of the total resource base. The remaining 15 percent is made up of Arctic and acid/sour gas resources.						Resource Base Changes(1)
												5-Year
						(billions of oil-equivalent barrels)		2014				Average
						Resource Additions/Acquisitions			3.2				6.5
						Revisions to Existing Fields			0.1				(0.7	)
						Production			(1.5	)			(1.6	)
						Asset Sales			(0.3	)			(0.7	)
						Net change versus year-end 2013			1.5				3.5
						Proved Reserves Replacement Ratio(1)(2)
						(percent of annual production replaced with proved reserves additions)

Proved Reserves

ExxonMobil’s resource base includes 25 billion oil-equivalent barrels of proved oil and gas reserves, equating to approximately 17 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 2014, we replaced 104 percent of the reserves we produced, including the impact of asset sales. We added 1.5 billion oil-equivalent barrels to proved reserves (80 percent liquids) while producing 1.5 billion oil-equivalent barrels. Excluding asset sales, our proved reserves replacement ratio was 111 percent. Key proved reserve additions resulted from North American unconventional activities.

ExxonMobil added more than 10 billion oil-equivalent barrels to proved reserves over the past 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 billion oil-equivalent barrels per year to proved reserves.

Revisions to proved reserves have averaged about 0.5 billion oil-equivalent barrels per year over the past five years, driven by effective reservoir management and the application of new technologies. We have more than replaced our production for 21 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⁾

By Geographic 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.

26		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

 

Worldwide Upstream Operations

 

 

 

ExxonMobil has an active exploration or production presence in 36 countries and production operations in 24 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 35 percent of net oil-equivalent production and 26 percent of Upstream earnings in 2014.				Americas Highlights			2014				2013				2012
				Earnings (billions of dollars)			7.1				5.6				5.5
				Proved Reserves (oil-equivalent barrels, billions)			12.7				12.0				11.8
				Acreage (gross acres, million)			46.0				46.2				47.0
				Net Liquids Production (million barrels per day)			0.8				0.7				0.7
				Net Gas Available for Sale (billion cubic feet per day)			3.7				3.9				4.2
				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

enhanced by activity in unconventional

plays, nine of which are estimated to

contain recoverable resources of

greater than 1 billion oil-equivalent

barrels. Future developments are also

planned for ExxonMobil’s extensive deepwater

Gulf of Mexico acreage position.

Gulf of Mexico/Gulf Coast

2014 net average production in the Gulf of Mexico was

51 thousand barrels of liquids per day and 159 million cubic feet of gas per day.

Deep Water ¡ In the deepwater Gulf of Mexico, we operate the Hoover platform

which 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.

		27

 

 

 

 

Drilling commenced on the Julia Phase 1 project with the newly built Maersk Viking drillship in the Gulf of Mexico.

Activity continued in the Keathley Canyon (KC) area. We are participating in the Anadarko-operated Lucius development (ExxonMobil interest, 23 percent) and are developing Hadrian South (ExxonMobil interest, 47 percent), situated in block KC-964, as a subsea tieback to the Lucius platform. Both projects were completed in 2014. Lucius production was initiated in early 2015.

Also in this area, ExxonMobil and its co-venturers continue to progress concept selection activities for development of the Hadrian North oil discovery (ExxonMobil interest, 50 percent), which is situated in 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 block WR-718. Project execution continues and drilling of the first well commenced in 2014, with first oil production 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 via subsea tieback to a spar facility. Well-drilling activities commenced in 2014 and start-up is planned for 2016.

 

We continue to expand and evaluate our substantial exploration portfolio of 1.2 million net acres in the deepwater Gulf of Mexico with investments in advanced seismic data to further enhance our understanding of the subsurface. ExxonMobil was awarded one Outer Continental Shelf (OCS) block in Sale 231, and three OCS blocks each in Sale 233 and Sale 238.   Conventional ¡ The Mobile Bay development offshore Alabama contributed net production of 107 million cubic feet of gas per day during 2014. We continue to realize cost efficiencies and capture environmental benefits associated with the consolidation of our sour gas plants in late 2010.   LNG ¡ Golden Pass Products LLC, a joint venture between ExxonMobil and Qatar Petroleum International, progressed federal permitting to add up to 15.6 million tonnes per year of export capacity to the existing Golden Pass LNG terminal, an import facility at Sabine Pass, Texas. This project gives 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 2014, front-end engineering design commenced and environmental permit applications were submitted to the Federal Energy Regulatory Commission.		Golden Pass Products in Texas is progressing a project to add up to 15.6 million tonnes per year of LNG export capacity to the existing terminal.

28		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

Worldwide Upstream Operations, continued

 

 

U.S. Onshore Texas and Louisiana

ExxonMobil is a leading producer in Louisiana and Texas with strong positions in all of the major conventional and unconventional plays, including the Permian Basin. In 2014, onshore net production in Texas and Louisiana averaged 105 thousand barrels of liquids per day and 1.6 billion cubic feet of gas per day.

Conventional ¡ ExxonMobil is a leading leaseholder and producer in the Permian Basin with over 1.5 million acres of leasehold. After ramping up activity to eight operated conventional drilling rigs in 2014, we completed 155 wells across multiple fields, including Russell, Goldsmith, Fullerton, Cornell, and Mahoney. More than 60 workover rigs were also active in the Permian, increasing production by opening up additional zones with fracture stimulation treatments. We are optimizing development and expanding infrastructure to facilitate rapid production growth, including expansion of water handling and gas processing capacity.

Unconventional ¡ ExxonMobil holds 227,000 net acres in the Haynesville/Bossier Shale of East Texas and Louisiana, where we continue to capture benefits from our drilling and completion improvements.

In the Barnett Shale play in North Texas, we continue to develop and maintain our leasehold of 211,000 net acres. In the Freestone tight gas trend, where ExxonMobil holds 295,000 net acres, we focused on operating efficiently and making disciplined investments to offset decline.

Unconventional development in the Permian has been a key focus for us in 2014 and will drive our U.S. production in the future. Three strategic transactions, enabled by our large and diverse portfolio, added 65,000 acres to our already strong unconventional Permian position highlighted by the Wolfcamp, Wolfbone, Wolfberry, and Bone Springs reservoirs. In 2014, we increased our operated unconventional Permian rigs to 10 and have plans to further increase activity over the next several years. With this investment, our production will continue to grow after rising 15 percent during 2014 on a large base. We remain encouraged by our development of the prolific Wolfcamp formation in the Midland Basin.

 

		Technology: Facility Design Innovations Reduce Cost
		ExxonMobil’s expertise in process engineering and equipment technologies is driving costs down through process intensification and operating efficiency enhancements. Integration of Upstream and Downstream processing technology uniquely positions our scientists and engineers to efficiently take advantage of expertise across the company.
		ExxonMobil’s applied research in compact separation technologies has led to cost reductions in Point Thomson (North Slope of Alaska) and Hadrian South (Gulf of Mexico). In both cases, the use of compact separation devices has enabled the manufacture and deployment of smaller separation modules, which is especially critical for remote and offshore applications. At Hadrian South, our application of compact separation technology enabled the use of a smaller separation module to support the subsea tieback of a satellite gas field to maximize condensate recovery, while minimizing changes to the design of the supporting structure.
		We are applying our experience to develop a compact subsea separation system, by integrating commercially available equipment with our own proprietary technologies. The overall performance of this system has been validated through a rigorous qualification program in preparation for first commercial application. Such compact subsea separation systems will enhance the development of deepwater fields within ExxonMobil’s offshore portfolio by increasing the overall recovery of hydrocarbons from the reservoirs.   PHOTO: Application of compact separation technologies reduces development costs at remote locations, such as Point Thomson on the North Slope of Alaska.

		29

 

 

 

 

Mid-Continent and Appalachia ExxonMobil produces oil and gas throughout the mid-continent states, including Arkansas, Colorado, Kansas, Montana, New Mexico, North Dakota, Oklahoma, Utah, and Wyoming, as well as the Appalachian states of Pennsylvania and West Virginia. Average net production from these areas was 113 thousand barrels of liquids per day and more than 1.6 billion cubic feet of gas per day in 2014.   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 in early 2012, and record carbon dioxide sales of 337 million cubic feet per day were reached in late 2014. The LaBarge facilities processed an average of 700 million cubic feet of inlet gas per day in 2014.
				Production in the Bakken has increased sixfold since our entry into the play in 2008.

Unconventional ¡ The Bakken Shale remained one of our most active unconventional programs in 2014 with well completions and production volumes again reaching all-time highs. ExxonMobil currently holds 544,000 net acres of high-quality resource in this play. Through the deployment of 16 rigs by year end, net operated production in the Bakken increased 38 percent in 2014.

The liquids-rich Woodford Shale in the Ardmore Basin of southern Oklahoma was another active area in 2014. We operated 10 rigs across our more than 335,000 net acres and continued delineation of the oil-rich Woodford Shale in the Marietta Basin. We continue to progress 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 450,000 net acres.

ExxonMobil holds a material position in the Marcellus Shale of 583,000 acres across Pennsylvania and West Virginia, and 55,000 acres in the promising Utica Shale in Ohio. Our cryogenic plant in Butler County, Pennsylvania, continues to enhance returns from our Marcellus production by capturing natural gas liquids. In Utah, Colorado, and New Mexico, production from more than 1 million net acres in the Uinta, Piceance, Raton, and San Juan plays has continued.

 

California
Net production from fields offshore California averaged 28 thousand barrels of liquids per day and 23 million cubic feet of gas per day during 2014. 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 2014, development drilling continued at the SYU Harmony platform.   ExxonMobil also has a 48-percent equity share in Aera Energy LLC’s operations, comprising eight fields and about 11,000 wells that produce 60 thousand net oil-equivalent barrels per day of a mixture of heavy and conventional oil with associated natural gas.				Production from our Santa Ynez Unit offshore development is processed at the Las Flores Canyon Plant in California.

30		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

Worldwide Upstream Operations, continued

 

 

Alaska

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 infrastructure complete, drilling and completions preparation under way, and large processing module fabrication in progress. Average net production was 96 thousand barrels of liquids per day in 2014.

Together with the State of Alaska and co-venturers, ExxonMobil is continuing to advance the Alaska LNG project to commercialize Alaskan gas resources. The pre-front-end engineering design studies are ongoing to further define and optimize the design. In addition, extensive field work to gather data for the Environmental Impact Statement is progressing. In September 2014, the project initiated the regulatory permitting process by pre-filing with the Federal Energy Regulatory Commission.

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 the country and possess a significant portfolio of major projects, both onshore and offshore.

Offshore Canada Operations

Beaufort Sea ¡ 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 2014, we continued to work closely with regulators, both federal and territorial, to progress approval for exploration drilling.

Hebron ¡ 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 2014, construction of the concrete gravity-based structure continued in Newfoundland. The partially built structure was floated to a deepwater site where construction and mechanical outfitting are ongoing. Fabrication of topsides modules continues in Newfoundland and South Korea. Start-up is expected in 2017.

Hibernia ¡ The Hibernia field (ExxonMobil interest, 33 percent) offshore Newfoundland is operated by Hibernia Management and Development Company Ltd., utilizing its own employees, and selected secondees and processes from ExxonMobil. Hibernia’s net production averaged 25 thousand barrels of oil per day in 2014. Progress continued on the Hibernia Southern Extension project (ExxonMobil interest, 27 percent), a subsea tieback to the existing Hibernia platform that will access recoverable resources of approximately 170 million gross oil-equivalent barrels. Subsea water injection commenced in November 2014, and drilling and completions operations are under way for the remaining platform and subsea wells.

 

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Onshore Canada Operations Cold Lake ¡ In 2014, the Cold Lake heavy oil field in Alberta (Imperial Oil interest, 100 percent) achieved production of 114 thousand net barrels of oil per day. Cold Lake is one of the largest thermal in situ heavy oil projects in the world. It has more than 4,200 wells directionally drilled from multiple satellite pads tied back to central facilities, which reduce surface land requirements. Cyclic steam stimulation is used to recover bitumen and recovery is increased through the use of leading-edge thermal 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 will increase capacity by 50 thousand barrels of bitumen per day. In addition, experimental pilots are currently under way to test solvent-based recovery technologies that would further enhance recovery and lower greenhouse gas emissions.		The Cold Lake Nabiye Expansion project began steam injection in January 2015.

Horn River ¡ 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 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.

Kearl ¡ 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 bitumen averaged 66 thousand net barrels per day in 2014. Construction is nearing completion on the expansion project, which is expected to produce an additional 110 thousand barrels of bitumen per day.

Montney and Duvernay ¡ ExxonMobil continued to delineate our 629,000 net acres in the liquids-rich Montney and Duvernay plays. By year-end 2014, six rigs were active and our recently commissioned 90-million-cubic-feet-per-day Kaybob gas plant was approaching full capacity.

Steam-Assisted Gravity Drainage (SAGD) ¡ In 2014, ExxonMobil and Imperial Oil also continued to evaluate oil sands acreage in the Athabasca region on both in situ and mining leases including Aspen, Clark Creek, Corner, Grand Rapids, and Clyden. ExxonMobil is continually leveraging our extensive acreage position in Canada to maximize value.

Syncrude ¡ The Syncrude oil sands mining operation (Imperial Oil interest, 25 percent) produced synthetic crude averaging 60 thousand net barrels per day in 2014. 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 Mildred Lake Mine Sustaining project was completed in 2014.

West Coast Canada (WCC) LNG ¡ ExxonMobil and Imperial Oil are in the early stages of project assessment and planning for a proposed LNG project in Prince Rupert, British Columbia. Through the jointly owned affiliate WCC LNG Ltd., ExxonMobil and Imperial Oil received an export license in 2013 from the National Energy Board to export up to 30 million tonnes of LNG per year for 25 years.

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South America   Argentina In Argentina, ExxonMobil holds a 51-percent interest in the Chihuidos concession. During 2014, we sold net daily gas production of 21 million cubic feet to local markets.   ExxonMobil continued its exploration drilling and well-testing campaign in the highly prospective Vaca Muerta shale formation in the Neuquén Basin where we hold more than 900,000 net acres. We expanded our acreage position by approximately 30,000 net acres through the capture of the Parva Negra Este block in 2014. Drilling, completion, and testing activities continued on two ExxonMobil-operated horizontal wells with encouraging early results.   Brazil ExxonMobil captured a 35-percent operating interest in the POT-M-475 deepwater block in 2014. Seismic operations on the POT-M-475 and CE-M-603 blocks are planned for 2015.   Colombia ExxonMobil has an interest in four blocks and a technical evaluation agreement for one block in the emerging tight liquids play. The drilling and initial short-term test of our first unconventional exploration well is planned for 2015. In the Colombian offshore, ExxonMobil was awarded a 33-percent interest in the COL-4 technical evaluation agreement covering 889,000 net acres in deep water during the 2014 tender round. In the heavy oil play, ExxonMobil is finalizing its obligations under a technical evaluation agreement in the CPE-3 onshore block.

Guyana

ExxonMobil holds a 100-percent operating interest in the Stabroek deepwater block (6.6 million net acres) offshore Guyana. In 2014, we reduced our operating interest to 45 percent, pending government approval, with plans to drill a deepwater well in 2015.

Venezuela

The Cerro Negro and La Ceiba assets were expropriated without compensation by Venezuela in June 2007. Prior to expropriation, ExxonMobil affiliates owned a 41.7-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. In October 2014, ICSID issued an award of $1.6 billion, plus interest dating back to 2007, in favor of ExxonMobil. Venezuela is challenging the award and the matter remains pending.

 

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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 2014, European operations accounted for 16 percent of ExxonMobil’s net oil and natural gas production, and 10 percent of Upstream earnings.   ExxonMobil continues to progress exploration activities and development projects in Europe. We are increasing recovery from existing producing assets through work programs and the implementation of new technology. We continue to study the exploration potential near our Domino						Europe Highlights			2014				2013				2012
						Earnings (billions of dollars)			2.6				3.4				4.0
						Proved Reserves (oil-equivalent barrels, billions)			2.1				2.3				2.5
						Acreage (gross acres, million)			18.3				21.2				43.7
						Net Liquids Production (million barrels per day)			0.2				0.2				0.2
						Net Gas Available for Sale (billion cubic feet per day)			2.8				3.3				3.2
						Europe Production   (millions of oil-equivalent barrels per day, net)
gas discovery in the Romanian Black Sea. Additionally, ExxonMobil provides natural gas supply to the European market through LNG from our joint ventures with Qatar Petroleum, including receiving terminals in the United Kingdom and Italy where ExxonMobil has equity interests.

    

 

 

Faroe Islands

Drilling was completed on the Brugdan-2 wildcat well on Faroes license L006 in 2014. The well did not

encounter any hydrocarbons and ExxonMobil subsequently relinquished all Faroes acreage.

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 2014, these

fields generated an average net production of

425 million cubic feet per day. During the

year, we successfully commissioned a new

30-megawatt electric cogeneration facility

located within ExxonMobil’s Grossenkneten

sour gas plant. This new cogeneration

unit can supply all of the electricity

required to run the gas plant and a

nearby compressor station. In addition,

it can produce 80 tonnes per hour of

steam for use in the Grossenkneten Plant.

The unit is expected to reduce ExxonMobil’s

indirect CO₂ emissions by up to 70 thousand

tonnes per year.

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.

34		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

 

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Ireland

ExxonMobil is in the process of relinquishing ownership of the Dunquin FEL 3/04 and Cuchulain FEL 1/99 licenses.

Italy

The Adriatic LNG terminal (ExxonMobil interest, 71 percent), located 10 miles offshore of Porto Levante in the northern Adriatic Sea, is the world’s only fixed offshore LNG storage and regasification terminal. In 2014, 50 LNG cargoes were delivered, providing about 3.2 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 1.7 billion cubic feet of gas in 2014. The majority of this production comes from the Groningen field (ExxonMobil interest, 30 percent), which is Europe’s largest natural gas field. In 2014, NAM commenced deliveries from the Underground Storage Expansion project at Norg, which helps to sustain Groningen gas deliveries. ExxonMobil continues to evaluate exploration opportunities with NAM.

Norway

ExxonMobil is among the largest oil and gas producers in Norway, with average net production of 152 thousand barrels of liquids per day and 450 million cubic feet of gas per day in 2014. We operate offshore producing fields, including Ringhorne (ExxonMobil interest, 100 percent), Ringhorne East (ExxonMobil interest, 77 percent), and Balder (ExxonMobil interest, 100 percent). In 2014, net production averaged 50 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 2015-2016. We are assessing the potential for further drilling at Ringhorne in the future.

 

 

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ExxonMobil also has significant equity participation in approximately 20 partner-operated fields offshore Norway. In 2014, average net production from these fields yielded 102 thousand barrels of liquids per day and 435 million cubic feet of gas per day. A new field in the Grane area, Svalin, came on production in 2014. This field is a subsea development tied back to the Grane platform.

During the year, ExxonMobil’s equity in Snorre was reduced from 17.8 percent to 17.5 percent following an equity redetermination settlement. At Grane, gas injection was initiated for improved oil recovery. Progress continues on new subsea technology with the execution of the Aasgard Subsea Compression (ASC) project (ExxonMobil interest, 13.5 percent). 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. Testing of the pilot compressor was completed in 2014 and installation of the first production compressor is planned for 2015.

In 2014, ExxonMobil held two exploration licenses: 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. Additional seismic data and interpretation in Møre Vest determined the low exploration potential and ExxonMobil relinquished the license after fulfilling our program commitments.

 

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. Concept selection activities are progressing. Additional drilling was completed in 2014 with the results currently being evaluated. During the year, ExxonMobil continued exploration drilling with the Pelican South-1 well in the Neptun Deep block. The well will be completed in 2015. ExxonMobil expanded its position in the Romanian Black Sea with an agreement to purchase the deepwater portion of the Midia Deep License, covering 53,000 net acres.   Ukraine In August 2012, an ExxonMobil-led consortium won the tender for the Skifska offshore block in the Black Sea totaling 3.7 million net acres (ExxonMobil interest, 90 percent). Due to the political situation in Ukraine, the negotiations to conclude the Skifska offshore block remain in force majeure.

United Kingdom

ExxonMobil holds interests in more than 40 producing fields in the North Sea, principally through a joint venture with Shell. In 2014, average net production from these fields was 23 thousand barrels of liquids per day and 283 million cubic feet of gas per day. Drilling activities are ongoing and a number of further development opportunities are under evaluation.

In December 2014, the United Kingdom’s 28th offshore licensing round awarded ExxonMobil a 50-percent interest (Shell operated) in two licenses, consisting of 129,000 net acres in the North Sea. Additional seismic data interpretation will begin in 2015.

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

36		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

 

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Africa				Africa Highlights		2014		2013		2012
ExxonMobil is one of Africa’s leading oil producers. Our operations in Africa accounted for 12 percent of our 2014 net oil and natural gas production, and 13 percent of total Upstream earnings. In addition to producing activities, we have ongoing exploration activities. ExxonMobil holds interests in 21 deepwater blocks totaling over 12 million net acres.				Earnings (billions of dollars)		3.7		4.5		7.2
				Proved Reserves (oil-equivalent barrels, billions)		1.4		1.5		1.7
				Acreage (gross acres, million)		24.4		23.0		14.1
				Net Liquids Production (million barrels per day)		0.5		0.5		0.5
				Net Gas Available for Sale (billion cubic feet per day)		–		–		–
				Africa Production   (millions of oil-equivalent barrels per day, net)
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 131 thousand barrels

of oil per day in 2014. 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. Block 15 was Angola’s second-highest-

producing block in 2014 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. Development

drilling began in 2014 and 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 2014, 15 discoveries have been made

on the block with a gross recoverable resource potential of

approximately 5 billion oil-equivalent barrels.

 

The Cravo-Lirio-Orquidea-Violeta (CLOV) project achieved start-up in June 2014. Located in 4,100 feet of water, the project is producing over 160 thousand barrels of oil per day via subsea wells tied back to a new FPSO vessel.

Within Block 17, design activities are also progressing for the Pazflor Satellites project that involves tie-in to the existing Pazflor subsea infrastructure and FPSO vessel. In 2014, concept optimization work and front-end engineering were completed, and the project is expected to start production in 2018.

Block 32 ¡ Development planning activities continue for Block 32 where ExxonMobil owns a 15-percent interest. Through year-end 2014, 13 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, with estimated recovery of about 600 million barrels of oil. A final investment decision was made in 2014 and execution stage activities are progressing. Start-up is anticipated in 2017. Block 32 co-venturers drilled the successful

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Execution of the second phase of the Kizomba Satellites project in Angola leverages the existing floating production, storage, and offloading (FPSO) vessel and facilities.

 

Cominhos-3 wildcat, which is envisioned to support the next phase of development. Additional wildcat wells are planned in 2015.   Chad ExxonMobil is Chad’s leading oil producer (ExxonMobil interest, 40 percent) with average net production of 28 thousand barrels of oil per day in 2014. Production drilling was conducted in 2014 with two rigs in the Bolobo and Miandoum fields located near Kome. 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.   Côte d’Ivoire Two frontier deepwater blocks, CI-602 and CI-603, were captured in Côte d’Ivoire in 2014. Assessment of the resource potential is under way, with 3D seismic data acquisition planned in early 2015.

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 1 billion barrels in its 18 years of production. In 2014, net production averaged 32 thousand barrels of oil per day. A drilling and wellwork campaign began in 2014 and will continue through 2015.

Gabon

ExxonMobil participated in the Sputnik wildcat well on the Arouwe block in 2014. The block is currently under evaluation.

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Liberia

ExxonMobil holds an 83-percent interest in Liberia Block 13 covering approximately 520,000 net acres. Technical evaluation is ongoing, with plans for drilling to be defined.

Madagascar

ExxonMobil holds an interest in more than 9.3 million net acres in the Majunga Basin offshore Madagascar. Interpretation of the 2D seismic data acquired in 2013 is under way to better understand the resource potential.

Nigeria

ExxonMobil continues to develop our interest in offshore Nigeria. We operate a shallow-water joint venture with the Nigerian National Petroleum Corporation offshore southeastern Nigeria (ExxonMobil interest, 40 percent for crude and condensate; 51 percent for natural gas liquids) as well as the deepwater Erha, Erha North, and Usan 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 2014, net production in Nigeria averaged 298 thousand barrels of liquids per day.

Nigeria – Deep Water

Erha/Erha North ¡ The Erha development (ExxonMobil interest, 56 percent) is located 60 miles offshore in 3,900 feet of water. The development has a capacity in excess of 200 thousand barrels per day and consists of more than 30 subsea wells tied back to an FPSO vessel.

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 an expected peak production rate of approximately 60 thousand barrels of oil per day. In 2014, we progressed fabrication and commenced installation and drilling activities. Start-up is targeted for late 2015.

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 project concept expected to develop more than 500 million oil-equivalent barrels.

Bonga Northwest ¡ Bonga Northwest (ExxonMobil interest, 20 percent) achieved start-up in August 2014. The project will develop approximately 100 million barrels of oil via subsea tieback to the existing Bonga FPSO vessel, which began production from the Bonga field in 2005.

 

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OML 138 / OML 139 / OPL 223 ¡ Two successful wildcat wells were drilled on OML 138 in 2014, south of the Usan field. ExxonMobil is currently evaluating development options and assessing additional potential on the block.   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 assumed operatorship of this asset in February 2014.				ExxonMobil assumed operatorship of Usan offshore Nigeria in 2014.

 

		Technology: Enhancing Well Performance
		ExxonMobil invests in technology to enhance reliability and longevity, ensuring our wells produce and facilities operate efficiently over the life of an asset.
		Advances in well screen technology and well simulation have enabled access to profitable barrels of oil that otherwise would have remained in place. Our expertise in computational fluid dynamics and proprietary well performance simulation is leveraged to design and optimize well completions for a variety of operating conditions. ExxonMobil’s MazeFlo completion technology, developed using this approach, mitigates mechanical screen damage to improve reliability in sand-prone well production.
		Offshore Nigeria, a well shut-in for sand production was fitted with a MazeFlo screen run inside the existing completion. The well has now produced an additional 2.7 million barrels of oil that would have otherwise remained shut-in. These
		barrels were produced at significant savings compared to a sidetrack well, the next best alternative.   ExxonMobil’s proprietary well simulation and completion design capabilities are also being applied to develop innovative passive inflow control devices for production conformance and water injection applications to maximize profitable recovery in new and existing wells worldwide.   PHOTO: ExxonMobil engineers design novel completion technologies for enhanced well performance.

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Nigeria Shelf – Joint Venture		Natural gas liquids are produced from the East Area Complex in Nigeria.
ExxonMobil’s portfolio in the Nigerian shelf encompasses 70 discovered fields. We have ongoing activities to maximize recovery, including optimization of base operations and a series of platform upgrades. There has not been any active drilling program in the joint venture since August 2014 when the last drilling rig was demobilized. However, exploration activities continue in an effort to identify new opportunities, with future seismic data acquisition planned.   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 and drilling activities concluded in May 2014. Peak production from Phase 1 reached
70 thousand barrels of liquids per day, with recovery anticipated to exceed 120 million barrels of oil and natural gas liquids. In 2014, engineering and contracting activities continued on Phase 2 of the Satellite Field Development, incorporating learnings from Phase 1.

Natural Gas Liquids ¡ Natural gas liquids are produced from the Oso Natural Gas Liquids project and the East Area Natural Gas Liquids II project (ExxonMobil interest, 51 percent). The projects are expected to recover around 670 million barrels of natural gas liquids. In addition, they have contributed to a reduction in flaring since start-up in 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 and government approval is being progressed. 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 ExxonMobil holds a 75-percent interest in the Tugela South Exploration Right. Future exploration rights in four offshore areas, and ExxonMobil’s interest in them, remain subject to South African governmental approval. We have initiated exploration activities, including geological studies, environmental impact assessments, and community engagement.   Tanzania Four exploration wells were drilled on Block 2 (ExxonMobil interest, 35 percent) in 2014, resulting in two natural gas discoveries at Piri and Giligilani. These two discoveries bring the total discovered resource to approximately 21 trillion cubic feet of natural gas in place. Operator Statoil and ExxonMobil are continuing development planning, onshore site selection, and commercial discussions regarding a potential joint LNG plant with adjoining blocks.

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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 33 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 2.6 billion barrels of oil since its 1997 start-up. In 2014, ACG production averaged 18 thousand barrels of net oil per day. A sixth producing platform was started up in January 2014.		Asia Highlights		2014				2013				2012
		Earnings (billions of dollars)			13.2				13.0				12.7
		Proved Reserves (oil-equivalent barrels, billions)			7.6				7.9				7.7
		Acreage (gross acres, million)			211.0				60.3				31.5
		Net Liquids Production (million barrels per day)			0.6				0.8				0.8
		Net Gas Available for Sale (billion cubic feet per day)			4.1				4.3				4.5
		Asia Production   (millions of oil-equivalent barrels per day, net)

 

Hong Kong ExxonMobil completed the sale of its interest in an electricity generation partnership in Hong Kong in May 2014, including its 60-percent shareholding in Castle Peak Power Company Ltd. and its 51-percent interest in Hong Kong Pumped Storage Development Company Ltd.

42		EXXONMOBIL 2014 FINANCIAL & OPERATING REVIEW

 

 

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Indonesia

ExxonMobil operates the onshore Arun and Arun satellite fields, and the North Sumatra offshore field. The natural gas from these fields is processed at the PT Arun LNG Plant. In 2014, net production from these fields averaged 79 million cubic feet of gas and 1 thousand barrels of associated liquids per day. The last cargo from the plant was exported in 2014 and gas is now directed to the domestic market.

In the Cepu area, onshore Java (ExxonMobil interest, 45 percent), construction of the 165-thousand-barrel-per-day Banyu Urip development is over 90 percent complete. Sixty miles of onshore and offshore pipelines have been installed, and the floating storage and offloading vessel was safely completed, towed, and installed 14 miles offshore in the Java Sea. Construction of the central processing facilities continues along with commissioning activities in preparation for start-up. Two rigs are executing the development drilling program ahead of plan, with 38 of 48 total wells complete. In 2014, we increased existing production to more than 40 thousand barrels per day and will continue to ramp up production to full field capacity in 2015.

Front-end engineering design commenced in June 2014 on the Cepu Gas project, a unitized development covering the Jambaran and Tiung Biru gas fields with PT Pertamina EP Cepu as the unit operator. A revised plan of development was submitted to the government regulator for approval, and gas sales agreements were progressed.

In December 2013, our Indonesian affiliate, Esso Natuna Ltd., signed a Fourth Restated Principles of Agreement with the Government of Indonesia that provided the framework to negotiate for a new production sharing contract (PSC) to develop Natuna’s hydrocarbon resources. Discussions to finalize an East Natuna PSC continue. During 2014, ExxonMobil exited the deepwater Surumana and Mandar blocks, and the onshore Java Gunting and Kalimantan Barito CBM blocks.

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, 33 percent). In 2013, we reduced our interest from 60 percent to 25 percent, and in 2014 we amended the contract, increasing our interest to 33 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, and construction of new production facilities and associated support infrastructure.

In 2014, we continued with redevelopment activities and received approval for the West Qurna I long-term development plan. Production from West Qurna I averaged 340 thousand barrels per day in 2014.

In October 2011, ExxonMobil signed six PSCs covering more than 848,000 acres in the Kurdistan Region of Iraq. In 2014, ExxonMobil continued acquisition of 2D seismic data and drilling operations on two ExxonMobil-operated wells. Operations were temporarily suspended in the third quarter of 2014 due to the security situation and are expected to resume in 2015 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 2.4 billion barrels of oil from a total gross resource of more than 6 billion barrels. In 2014, net production from these fields averaged 144 thousand barrels of liquids per day and 153 million cubic feet of gas per day. Front-end engineering was completed, and early works were progressed in 2014 to increase production capacity by as much as 265 thousand barrels of oil per day and extend current production rates as reservoir pressure declines.

Kashagan ¡ As a participant in the North Caspian Sea Production Sharing Agreement (ExxonMobil interest, 17 percent), we are working with consortium members to progress multiphased development of the massive Kashagan field located offshore in the Caspian Sea. Phase 1 includes an offshore production and separation hub on an artificial island, several drilling islands, and an onshore processing plant. Following a brief production period in 2013, operations were suspended due to a leak discovered in the onshore section of the gas pipeline. Following an extensive technical investigation, a decision was made to replace both the oil and gas pipelines. New pipe has been ordered and pipeline construction is planned to begin in spring 2015 with target completion in the second half of 2016.

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Caspian Pipeline Consortium ¡ The Caspian Pipeline Consortium (ExxonMobil interest, 7.5 percent) operates a pipeline that runs from the Tengiz field in Kazakhstan to the Novorossiysk marine terminal on the Russian Black Sea coast. Currently, the consortium is constructing an expansion project that will increase system capacity from 0.6 million to 1.4 million barrels per day. Initial expansion capacity became available in February 2014 with completion of the remaining phases expected through 2016. This pipeline system represents the lowest-cost export option for Kazakh crude oil, with both TCO and future Kashagan developments as major shippers.

Malaysia

ExxonMobil operates 34 platforms in 12 fields in Malaysia, and is one of the country’s major suppliers of crude oil and natural gas. Net production in 2014 averaged 33 thousand barrels of liquids per day and 339 million cubic feet of gas per day.

The Tapis Enhanced Oil Recovery project (ExxonMobil interest, 50 percent) started up in September 2014 and is Malaysia’s first large-scale, full field offshore implementation of water-alternating-gas injection. The project will significantly rejuvenate and improve oil recovery from the Tapis field, which has been in production since 1978. The main component of the project is the Tapis R central processing platform equipped with 390-million-cubic-feet-per-day gas compression and 270-thousand-barrels-per-day water injection facilities. The Tapis R platform weighs over 23,000 tonnes, making it the heaviest platform constructed in Malaysia by ExxonMobil.

The Telok and Damar projects that started up in 2013 and 2014, respectively, add over 600 million cubic feet per day of gas facility capacity to supply the Malaysian domestic market.

Qatar

ExxonMobil participates in the RasGas and Qatargas LNG projects, the Al Khaleej and Barzan gas projects, as well as the Helium and common facilities projects, all of which are supplied by Qatar’s North Field, the world’s largest non-associated gas field. In 2014, production from ExxonMobil and Qatar Petroleum joint ventures exceeded 60 million tonnes of LNG reliably distributed to worldwide customers.

ExxonMobil and Qatar Petroleum also have joint interests outside of Qatar, including three LNG terminals located in Italy, the United Kingdom, and the United States.

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

Barzan ¡ The Barzan project will supply up to 1.4 billion cubic feet per day of natural gas, primarily to Qatar due to its rapidly growing infrastructure and industry requirements. The three offshore wellhead platforms are commissioned and have transitioned to operations. Development drilling of all production wells is complete and pipelines are installed. Onshore construction is nearing completion and commissioning is ongoing. Start-up is planned for 2015.

The Barzan project in Qatar will produce 1.4 billion cubic feet per day of sales gas when onstream in 2015.

 

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Worldwide Upstream Operations, continued

 

 

Qatargas ¡ ExxonMobil participates in the Qatargas 1 and Qatargas 2 joint ventures with interests ranging from 10 to 30 percent. Qatargas 1 consists of three trains with a total capacity of 9.9 million tonnes per year, delivering LNG primarily to Japan and Western Europe. Qatargas 2 consists of two 7.8-million-tonnes-per-year trains. Deliveries of LNG from Qatargas 2 utilize a fleet of Q-Flex and Q-Max vessels, the world’s largest LNG carriers. The Qatargas operations also produce associated products including condensate, liquefied petroleum gas, helium, and sulfur.

RasGas ¡ RasGas is a joint venture between Qatar Petroleum and ExxonMobil, with 70-percent and 30-percent interests, respectively. RasGas operates a total of seven LNG trains with capacities ranging from 3.4 million to 7.8 million tonnes per year with a combined production capacity of 36.3 million tonnes per year. LNG from the seven trains is sold predominantly to the Asian and European markets. RasGas also employs a fleet of LNG carriers, including Q-Flex and Q-Max vessels. In addition to LNG, RasGas also produces substantial volumes of associated products including condensate, liquefied petroleum gas, helium, and sulfur.

Helium ¡ The RasGas-operated Helium 2 project started operations in 2013. The Helium 2 project increases existing capacity by 1.3 billion cubic feet per year to 2 billion cubic feet per year, making Qatar one of the world’s largest helium producers. ExxonMobil participation in the Helium 1 and Helium 2 projects is 22 percent and 18 percent, respectively.

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

Russia

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

 

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than 7 miles offshore under the Sea of Okhotsk. In March 2014, the Yastreb rig set another record for the world’s longest well at 42,600 feet measured depth. Daily production from Chayvo and Odoptu in 2014 averaged 156 thousand barrels of oil and 240 million cubic feet of natural gas. Since the initial start-up of Sakhalin-1 in 2005, more than 500 million barrels of oil have been produced and exported to world markets. Additionally, over 530 billion cubic feet of natural gas have been supplied to Russian domestic customers.

Odoptu Stage 2 is a planned phased expansion that will add a well site and extended-reach wells, increase capacity, and recover additional resources. Engineering continues, civil works are progressing, and fabrication has commenced on this expansion project.

Sakhalin-1 Arkutun-Dagi ¡ Installation of facilities at the third Sakhalin-1 field, Arkutun-Dagi, was completed in 2014 and development drilling commenced to achieve peak production of 90 thousand barrels of oil per day. The platform is the largest offshore oil and gas installation in Russia, and it set an industry record for floating installation when the 42-thousand-tonne topside was installed in the summer of 2014. First production started in early January 2015.

Sakhalin Future Phase ¡ ExxonMobil continues to pursue potential development options for Sakhalin-1 gas resources, including LNG exports, domestic sales, and export gas sales via pipeline.

 

Our ability to deliver superior technology and project execution excellence afforded us entry into Upper Zakum in 2006. Upper Zakum (ExxonMobil interest, 28 percent) is one of the world’s largest oil fields, with an initial resource estimate of approximately 50 billion gross barrels of oil.

The offshore Upper Zakum field covers more than 450 square miles with production capacity exceeding 590 thousand barrels of oil per day. In association with our joint venture partners, we are applying leading-edge reservoir simulation and extended-reach drilling technology that will increase daily field production capacity to 750 thousand barrels of oil per day. Construction of all four artificial islands was completed in 2014, and initial civil and infrastructure activities continue. Engineering and procurement progressed for the island facilities, and module fabrication for these facilities commenced at several regional fabrication yards. Four drilling rigs are operating from the artificial islands and an additional two are being constructed. Early production from the first island commenced in November 2014.

Vietnam

In 2014, we continued to progress resource and technical definition, commercial negotiation, and execution planning activities. In addition, an exploratory well was spud in early 2015 to further assess the resource.

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Worldwide Upstream Operations, continued

 

 

The LNG plant construction and commissioning continues on Barrow Island for the Gorgon Jansz project in Australia.

 

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Gorgon Jansz ¡ In 2014, project execution activities continued on the 15.6-million-tonnes-per-year Gorgon Jansz LNG project (ExxonMobil interest, 25 percent). The development consists of subsea infrastructure for offshore production and transportation of hydrocarbons, three 5.2-million-tonnes-per-year LNG trains (nominal capacity), and a 280-million-cubic-foot-per-day domestic gas plant located on Barrow Island. The project includes the world’s largest CO2 sequestration project.

In 2014, all gas processing and utilities modules for the first LNG train were installed on Barrow Island, and approximately half of the second train modules were delivered to the island. The first LNG tank was completed and the second is well progressed. Three of the four condensate tanks were constructed. In addition, LNG export jetty construction was completed, all offshore and onshore pipelines were installed, and testing is ongoing. The subsea installation campaign is on track to finish in early 2015.

ExxonMobil, as work operator for Jansz-Io, drilled and completed all 10 development wells. Gas will be produced via one of the world’s longest subsea tiebacks, located in 4,430 feet of water.

Gorgon Area Expansion ¡ The exploration and appraisal drilling program in the Greater Gorgon area conducted through 2014 has confirmed the presence of additional high-quality gas resource that can support a potential expansion of the Gorgon project. Development planning is ongoing to assess expansion project feasibility and optimal project timing.

Scarborough ¡ Engineering studies and execution planning to further define and optimize the Scarborough Floating LNG (FLNG) project continue (ExxonMobil interest, 50 percent). FLNG is considered the lead development option based on a balance of economic, environmental, and social considerations. The project’s environmental approval for the FLNG concept was received in November 2013, which is another positive step in the ongoing appraisal of the project.

Papua New Guinea

The PNG LNG project (ExxonMobil interest, 33 percent) shipped its first cargo in May 2014 and has the capacity to produce 6.9 million tonnes per year of LNG to supply the growing energy demand in Asia. Construction of PNG LNG began in 2010 and took more than 190 million work hours to complete. In 2014, we also progressed development drilling in the Hides field using two custom-built drilling rigs.

ExxonMobil successfully acquired an additional 10,500 net acres in the PNG Highlands trend in 2014. We continued acquisition of a multiyear seismic program in the PNG Highlands to further evaluate our acreage portfolio. More than 75 miles of 2D seismic data were acquired during 2014 to guide future exploration drilling. Planning is under way to acquire additional 2D seismic data in 2015. ExxonMobil is also progressing the drilling of the Hides Deep exploration well with results expected in 2015. These opportunities may enable expansion of PNG LNG.

PNG LNG started up in April 2014, several months ahead of schedule.