UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): March 8, 2012
Exxon Mobil Corporation
(Exact name of registrant as specified in its charter)
| New Jersey | 1-2256 | 13-5409005 | ||
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) |
| 5959 LAS COLINAS BOULEVARD, IRVING, TEXAS | 75039-2298 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (972) 444-1000
(Former name or former address, if changed since last report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 2.02 | Results of Operations and Financial Condition |
| Item 7.01 | Regulation FD Disclosure |
A transcript of remarks made and questions answered by senior executives of the Registrant at an analyst meeting held on March 8, 2012, is attached as Exhibit 99.1. The slides presented at the analyst meeting are attached as Exhibit 99.2. This material is being furnished under Item 7.01.
In addition, information contained in the attached material regarding results of operations and financial condition for completed quarterly or annual periods is furnished pursuant to Item 2.02. Additional information responsive to Instruction 2 of Item 2.02 is furnished as Exhibit 99.3.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| EXXON MOBIL CORPORATION | ||||||||||
| Date: March 14, 2012 | By: | /s/ Patrick T. Mulva | ||||||||
| Name: | Patrick T. Mulva | |||||||||
| Title: | Vice President, Controller and Principal Accounting Officer | |||||||||
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INDEX TO EXHIBITS
| Exhibit No. |
Description | |
| 99.1 | A transcript of remarks made and questions answered by senior executives of Exxon Mobil Corporation at an analyst meeting held on March 8, 2012. | |
| 99.2 | Slides presented at an analyst meeting held on March 8, 2012 | |
| 99.3 | Frequently Used Terms and additional information. | |
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Exhibit 99.1
Exxon Mobil Corporation
Presentations and Q&A Session
Analyst Meeting
New York, NY
March 8, 2012
|
EXXON MOBIL CORPORATION ANALYST MEETING MARCH 8, 2012 New York, NY 9:00 a.m. ET | ||||
David Rosenthal (Vice President of Investor Relations and Secretary of the Corporation)
David Rosenthal: Good morning. For those of you that I’ve have not yet met, my name is David Rosenthal. I’m the Vice President of Investor Relations and Secretary for ExxonMobil, and I’d like to welcome everyone to ExxonMobil’s 2012 Analyst Meeting. But before we begin the program, I would like to familiarize everybody with the safety procedures here at the New York Stock Exchange.
There is an exit in the back of the room and one through the doors on my right. In the event of an emergency, New York Stock Exchange personnel will provide us with instructions on how to respond. They will also, in the case of an evacuation, direct us to the nearest exit. So please wait for the instructions if this were to occur. I also would like to ask that everybody now make sure that your BlackBerrys and cell phones are turned off.
Next, I would like to draw your attention to the cautionary statements that you will find in the front of your material. This statement contains information regarding today’s presentation and discussion. If you have not previously read this statement, I ask that you do so at this time. You may also refer to our website, exxonmobil.com, for additional information affecting future results as well as supplemental information defining key terms that we will use today.
Our review today will begin with Rex Tillerson discussing some of the key factors influencing the industry and the business environment, followed by a look at our financial and operating results and the competitive advantages which led to the strong performance across the business. Following Rex’s discussion we will take a short break.
And then Mark Albers and Andy Swiger will provide a look at how ExxonMobil is unlocking greater value in our Upstream. Rex will then provide an outlook on investment plans and production volumes and then close with some summary remarks. We will then conduct our question and answer session, and the meeting will end by noon.
It is now my pleasure to introduce our Chairman and CEO Rex Tillerson. Rex.
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Rex Tillerson (Chairman and CEO)
Well thank you, David, and good morning to everyone. It’s always nice to see you again in New York City, and we appreciate the great spring weather. It’s wonderful for a visit, but it’s really bad for natural gas prices. Also I want to welcome all of those who are maybe joining us either by listening in on the telephone or by way of the webcast. We’re delighted you could listen in today as well.
I’m pleased today to share with you our 2011 financial and operating results and also talk through some of the elements of ExxonMobil that we believe do give us certain competitive advantages that will allow us to continue delivering value for our shareholders for many, many years to come.
Our competitive advantages, combined with the strength of our approach to managing our business, we believe continue to distinguish ExxonMobil and really do put us in a unique position to help meet the world’s evolving energy needs.
The global business environment continues to provide a mix of challenges, but of course, with challenges also come opportunities. The global economic recovery is progressing at a mixed, but overall slow pace with particular challenges in Europe yet to be played out. While developed nations continue to manage fiscal concerns, developing nations are working to sustain stable growth while tempering inflation risk.
The Asia Pacific region has shown some signs of slowing, but overall continues, certainly, to outpace the U.S. and Europe. Despite some near term economic weakness, we project that over the next 30 years economic output will more than double as people around the world seek to improve their standard of living. This long-term growth requires nations to maintain appropriate and sustainable regulatory frameworks as they seek investments that enhance their security, their economic competitiveness and the environment.
While today’s economic and business environment does present its set of challenges, as I said, it also presents opportunities. And we believe our Company is well-positioned to help meet long-term global energy and petrochemical demand which is forecast over the long term to be quite robust.
By the year 2040, the world’s population is likely to expand by close to 2 billion people, approaching 9 billion inhabitants of the planet, while overall economic output will also more than double. Coincident with this expanding prosperity, ExxonMobil’s 2012 Outlook for Energy anticipates that global energy demand will grow by 30%, even with significant efficiency gains across the world.
Ensuring reliable and affordable energy supplies to support this human progress safely and with manageable impact on the environment will remain a challenge requiring a diverse set of broad-based solutions. The bar chart on the left shows projected demand growth from the year 2010 to the year 2040 by energy type. Oil, gas, and coal are the most widely used fuels today, providing about 80% of supplies.
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As we look ahead to the year 2040, we anticipate a gradual shift in the global energy mix. Oil will remain most prominent, while demand for natural gas will rise by about 60% and we believe will surpass coal to become the second most widely used source of energy. Natural gas is increasingly recognized as a reliable, affordable and relatively cleaner fuel for a wide variety of applications. And its growing importance is supported by technologies that enable vast new supplies.
We expect global demand for the least carbon intensive fuels, natural gas, nuclear, and renewables will rise at a faster than average rate. The anticipated growth of these fuels will be driven significantly by power generation requirements as global electricity demand increases by 80%.
In our outlook, we see stark differences in energy use as we compare nations and regions at different stages of economic development. On the left, we show the demand by fuel for the relatively mature economies represented by nations of the OECD. Here, even though economic output is expected to nearly double over the outlook period, we expect energy demand will remain essentially flat. This illustrates the magnitude of efficiency gains across these more mature and developed economies.
Over the period, we also see a shift in the mix of fuels. Oil demand will gradually taper down, reflecting significant fuel economy gains of personal vehicles, while less carbon intensive fuels will become more prominent. By the year 2040, we expect natural gas will meet about 30% of OECD demand.
On the right we see a very different picture. Our outlook is that demand in the developing world will increase by about 60% led by growth in the Asia Pacific countries. While efficiency gains will have a large impact, they will not be enough to offset the rise in energy needs associated with expanding prosperity for over 80% of the world’s population.
As a result, we expect all fuels to grow to meet demands for transportation, business and homes, industrial facilities, and electricity generation. Oil and natural gas will likely account for approximately 70% of the growth in meeting global demand. We expect that oil and other liquid fuels will remain the world’s largest energy source for the next 30 years, meeting about one-third of demand.
Advances in technology will continue to be important to help expand liquid fuel supplies. As conventional crude oil production holds relatively flat, demand growth will be met by newer sources. As you can see in the chart on the left, large gains are expected from global deepwater sources with production more than doubling through the year 2040.
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Natural gas liquids supply is also expected to increase as production of these resources benefit from established techniques used to extract shale gas. We also expect to see significant growth from unconventional resources, including oil sands and tight oil. Oil sands are likely to account for most of the unconventional supply through the year 2040, though contributions from tight oil will be significant. Biofuels see gains as well, rising to around 5% of liquids supply.
On the right is the outlook for natural gas supply and demand, which rising by 60%, will be the fastest-growing major fuel over the next three decades. An increasing share of global natural gas demand is expected to be met by unconventional supplies such as those produced from shale, coal bed methane and tight gas formations. By the year 2040, unconventional gas will account for 30% of global production, up from 10% in the year 2010, thus requiring a growth in volume of almost 400%.
An implication of both the oil and gas outlook is that there is a growing requirement for unconventional resource development along with expanding supplies from deepwater and conventional resources.
By 2040, we expect energy demand for the transportation sector to increase nearly 45% relative to today. The increase is driven by growth in non-OECD countries, where demand is expected to double as a result of rising economic prosperity. OEC demand is projected to be essentially flat, reflecting significant efficiency gains.
Despite the potential positive effects of demand growth on the downstream industry, we expect a very challenging business environment. This view reflects a global increase in industry refining capacity in countries around the world, the development of alternative fuels, and realized efficiency gains, many of which are mandated by governments.
There is also the ongoing potential, of course, for the expansion of regulatory-related policy and further mandates which would just add to the challenge for existing refining’s capabilities and may well further alter the fuel mix of the future.
As shown on the chart, the transportation product mix is changing. We expect a continuing shift of transportation fuel demand to diesel, driven in part by high growth rates in developing countries as they expand truck, marine and rail transportation. This expansion in the commercial transportation sector, including heavy duty vehicles is significant, with more than a 70% increase in demand expected by the year 2040 compared to the year 2010.
Gasoline demand is expected to be flat to down as personal vehicles grow more fuel efficient with ongoing improvements to the internal combustion engine and drive trains and as well as hybrid vehicles become more mainstream.
This chart illustrates our expected global demand trend for lubricants. Total lubes demand, which includes not only synthetic lubricants but also conventional lubes is growing at about 1% per year, primarily driven by growth markets in Asia Pacific. Total demand is expected to be nearly 20% higher in the year 2020 versus the year 2000.
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Over the next 10 years, the global synthetics sector is forecast to grow at 6% per year with the United States and China driving 40% of this growth. OECD total lubes demand is expected to be flat to down over the longer term as demand in the mature markets, including the United States, Western Europe and Japan is expected to only partially recover in the near term from the recession low point. However, synthetics demand continues to grow and improve in most OECD markets.
On the chemicals front, we expect global demand for commodity chemicals to continue the historical trend of exceeding GDP growth rates as you can see from the graph which shows global GDP growth in red and demand for key chemical commodities in blue. While variable year to year, chemical demand growth is projected to outpace GDP by 1.5 percentage points, again driven by improving prosperity in the developing countries. Two-thirds of the demand growth will come from Asia Pacific, of course led by China. Middle class households will purchase more packaged goods, appliances, cars and clothing, many of which contain the chemicals we produce.
Overall, chemical products such as plastics and synthetic rubber will continue to grow as preferred materials versus wood, paper and aluminum because of advantages in performance, economics and lifecycle energy consumption.
In the decades ahead, the world will need to dramatically expand energy supplies to meet growing demand. The scale of the challenge is enormous and will require the pursuit of all economic options to expand supplies in a way that is safe, secure, affordable, and environmentally responsible.
A commitment to the development of new energy technologies is also required to both expand supply of traditional fuels, as well advance new energy sources as we have recently seen with natural gas from shale and new supplies of oil from resources previously deemed non-commercial.
An unprecedented $1.5 trillion dollars per year of investment will be needed globally to develop technology and resources that expand and diversify the supply base. Governments play a major role by maintaining sound and reliable policies that reduce investor uncertainty.
We also know from experience that the best way to achieve our shared goal is by effectively managing and addressing the risks inherent in our business and by maintaining a relentless focus on operational excellence. Risk management is not only about preventing and mitigating negative impacts, but it is also about achieving and maximizing positive outcomes for consumers, stakeholders and investors.
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Risk management is fundamental to our business and ExxonMobil has established common worldwide approaches and expectations for addressing the risks that are inherent to our operations. These expectations are fully embedded in our culture, and we remain focused on continuously improving our ability to effectively identify and manage risk.
Our approach is supported by well-developed, clearly defined policies and procedures to ensure that we have a structured, globally consistent approach with the high standards in place. Management commitment and accountability in all aspects of the business are key to achieving our expected results. In addition, we rigorously apply high standards in our operations up front during the design stage to reduce or eliminate risks where possible.
Employee and contractor training is another essential element to managing risk in order to achieve appropriate competency at all levels within the organization and to embed the right behaviors.
We also employ a systematic approach to measure performance and seek continuous improvement across our business. All of this is done within a context of experience based, rigorously applied management systems. Let’s now look at one of the frameworks used to manage the risk profile for our business.
Broadly recognized as a model of success, ExxonMobil’s Operations Integrity Management System, or OIMS, provides a disciplined framework for managing safety, security, health, and environmental risk. OIMS establishes a common worldwide expectation for managing risk. It is used in ExxonMobil facilities worldwide. It is instilled into daily operations. It is not just a set of processes and procedures. It is how we think. It is how we operate.
It also provides the framework to meet or exceed local regulations or expectations where relevant regulations simply do not exist in less mature countries. We continually assess the framework and its effectiveness and incorporate learnings to further elevate performance. Let’s now move to our financial and operating results.
We measure our performance using a variety of financial and non-financial parameters. First, we strive for continuous improvement in safety, which we believe sets the foundation for strong financial and operating performance. We also invest in the business with discipline with the objective of providing superior shareholder value over the long term. And finally, as our businesses continue to deliver strong results, we look to provide robust returns to our shareholders through dividends and share purchases.
Overall, I’m pleased with our 2011 performance across all key measures and all business lines. First and foremost, we continued our relentless focus on operational excellence, including leadership and safety performance and strong environmental management. We also delivered excellent financial and operating results with superior returns. We continued to invest with discipline, focusing on creating long-term value while maintaining a perspective that transcends the year-to-year economic conditions.
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These results reflect the strength of our proven business model, which has enabled us to consistently produce strong returns for our shareholders including unmatched cash flow generation and shareholder distributions. Let’s now look more closely at our safety and environmental performance.
As many of you have heard me say often, nothing receives more management attention at ExxonMobil than the safety and health of our employees, our contractors, our customers, and the people who live and work in the areas where we operate. When we fail to do this, everyone is distracted from running the business. Our vision that Nobody Gets Hurt is a simple element of daily operational excellence. Our safety performance remains strong in the industry with a relentless focus on effective risk management.
Our 2011 safety data represents a basis change as a result of including XTO for the first time. XTO has always been committed to operating in a safe and responsible manner, and indeed, they were among the leaders of the segment of the industry that they performed in. They are now benefiting from ExxonMobil’s systematic and disciplined approach to safety, security, health, and environmental performance.
We remain dedicated to the highest standards of safety and health and are committed to improving upon past performance levels. To do so requires relentless focus and commitments at all levels of the business. An organization cannot become complacent or content with past safety performance, and we will not be satisfied until we can conclude each day and say nobody got hurt. Let’s now look at our environmental performance.
Meeting the world’s growing need for energy while minimizing the impacts on the environment is one of society’s biggest challenges. At ExxonMobil we’ve implemented rigorous environmental management programs that deliver ongoing improvement in our global environmental performance. Through our environmental business planning process, we drive performance considerations into the lifecycle of our operations.
The results of this disciplined focus are significant, particularly in the areas of energy efficiency. For example, we are on track to meet targets for improving energy efficiency across our entire global refining and chemical operations of at least 10% over the 10-year period of 2002 to 2012 and to our knowledge we are the only company that will meet that objective.
We also will continue to progress initiatives to reduce the hydrocarbon flaring associated with our Upstream operations. Since 2007 we have decreased hydrocarbon flaring by 50%. In 2011, hydrocarbon flaring was up due to reliability events and new operations that were started up. We have also reduced greenhouse gas emissions by nearly 12 million tons since the year 2007, which is equivalent to taking 2.4 million cars off of the road in the United States.
Additionally, we continue to focus on reducing releases. For example, ongoing efforts in our marine organizations resulted in 2011 being the second consecutive year with zero hydrocarbon spills from both company-operated as well as term-chartered vessels. In our current operations, as we develop projects for the future, we will continue working to “Protect Tomorrow. Today.”
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Let’s now take a look at our 2011 earnings. ExxonMobil led the industry with earnings of $41 billion in 2011, an increase of 35% over 2010 reflecting sound operational performance across our portfolio of businesses. By applying our proven business approach we continue to maximize the value of our asset base over the long term, providing resiliency through the business cycle.
To give these results further context, let’s look closer at our Upstream financial and operating performance. ExxonMobil’s Upstream earnings per barrel were $20.94 in 2011, and averaged $17.95 over the last five years, reflecting strong results across a very diverse portfolio of holdings. While low U.S. natural gas prices pressured earnings in 2011, our long-term view is for natural gas to continue to grow in importance in meeting energy needs.
We are well-positioned with a diverse, balanced portfolio to capture upside and minimize downside across the business cycle as we continue to gain benefits from our disciplined cost management approach, applications of operational excellence and new technology applications. Our Upstream, as with all of our businesses, has a relentless focus on maximizing the value of each asset.
Upstream volumes grew just over 1% in 2011, driven by project and work program performances in addition to continuing integration of XTO’s world-class unconventional assets. Effective risk management and a focus on operational excellence also served as a foundation for this performance.
ExxonMobil is the largest, non-government-owned producer of oil and gas, with volumes of 4.5 million oil equivalent barrels per day in 2011. We were the only company in our peer group with a production increase last year. Let’s take a look now at our reserves replacement performance.
The chart shows our reserve replacement ratio over the last five years. In 2011, we replaced 116% of reserves produced, excluding the impact of asset sales. This represents the 18th consecutive year in which we have replaced more reserves than we produced. Our proven reserve base now equals 24.9 billion oil equivalent barrels, up from 2010. Our ability to replace more reserves than we produce positions us to continue to deliver profitable volume growth in the future.
We’ll take a look now at how our quality portfolio and capital discipline support our return on capital employed performance. In 2011, ExxonMobil’s return on capital employed was an industry leading 24%, about 3 percentage points higher than the nearest competitor.
Over the 2011 to 2000 — 2007 to 2011 timeframe, which we believe is a better indicator, our ROCE averaged about 26%, nearly 6 percentage points higher than the nearest competitor or about a third higher. ROCE, while still strong, has been impacted by low natural gas prices in the United States.
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In addition, ongoing large investments nearing completion, such as Kearl, Papua New Guinea and the Singapore Parallel Train will put pressure on ROCE until the facilities start up and begin contributing to earnings. The industry is in a period of high capital investment necessitated by the world’s growing energy needs.
And we are making strategic investments to position us well to meet those needs and to sustain strong, resilient, long-term performance. Even with these considerations, our ROCE performance exceeds competition, again due to the disciplined investing approach and the advantages of our integrated model.
Our investments are tested across a range of economic conditions to ensure they are resilient through the business cycle. Once we test the economics, we ensure our projects are cost efficient by applying our project management systems that incorporate best practices from across the businesses and leverage our technology advantages.
Disciplined investing also helps prevent the need for write-offs, though our ROCE performance is truly driven by delivering the highest value on the most productive capital base among our competitors. Equally important in creating value and maintaining ROCE leadership is managing our existing asset base, which I’ll talk about next.
ExxonMobil has a longstanding practice of continually reviewing all assets for their contribution to the Company’s operational and financial objectives. The Company markets assets that for a variety of reasons may be of more value to others, while retaining assets which hold long-term shareholder value. This approach is fundamental to our business model.
As such, we have ongoing asset management activities to capture value. Over the past five years, we have generated $26 billion in proceeds associated with the asset sales across all of our business lines and almost $11 billion in earnings.
In 2011, cash flow from operations and asset sales was approximately $66 billion, an increase of nearly 30% from 2010, and included over $11 billion of proceeds associated with asset sales. Our cash balance at the end of 2011 was over $13 billion.
Strong cash flow enabled us to fund all attractive investment opportunities and allowed us to return $29 billion to shareholders in the form of growing dividends and share purchases. Our shareholder distributions last year, supported by our strong cash flow, were unmatched in the industry.
Another measure of the value we create through financial and operating performance is the amount of free cash flow remaining after fully funding all attractive investment opportunities. Over the past five years, our free cash flow, before shareholder distributions, was almost $146 billion. This is unmatched among our peers and higher than our — all of our competitors combined.
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Consistent, strong, free cash flow generation provides capacity for robust shareholder distributions and a strong financial position that allows us to pursue opportunities that we wish. Let’s now take a look at our CapEx profile.
In 2011, we invested a record $37 billion in capital expenditures to continue positioning the business for long-term growth and sustainability. Over the past five years we have invested $143 billion, demonstrating our ability to invest through the business cycle and capture new opportunities.
For example in 2011, we acquired the Phillips Company, which provided attractive acreage in the Marcellus and the Utica plays. We were also able to add acreage in the emerging liquids-rich shale plays at a very attractive cost. We pursue opportunities in all regions of the world and across all business lines.
In 2011, we continued progress on a number of major projects, with nine Upstream projects expected to come online during the years 2012 to 2013. Our approach to advancing — to investing is to advance all attractive opportunities that will provide acceptable returns across a broad range of industry and market conditions, while maintaining our focus on capital efficiency and discipline. I’ll comment on our future CapEx plans later. For now let’s look at distributions to shareholders.
Over the past five years, our shareholder distributions have provided a total yield of 34%, which exceeds the competitor average by more than 10% and exceeded the total yield of each competitor in the group over the same period. ExxonMobil’s average annual yield of 7.3% over the last five years also exceeds the competitor average of 5.1% and that of each competitor in the group.
We maintained our approach to dividends with a view to building long-term shareholder value and providing reliable dividend growth through both the ups and downs of the business cycle. Over the past five years, we distributed over $40 billion in dividends to shareholders. During this same period, we increased per share dividends 45%. Excuse me.
Since 1983, through expansions and contractions of the business cycle, shareholders have received annual per share dividend increases at an annualized growth rate of 5.7%, almost twice the rate of inflation. At the same time, our dividend growth rate was much less volatile than that of the S&P 500.
In addition to growing dividends, we have provided added flexibility in returns to shareholders through share purchases. We continue to deliver value through share purchases, which is an efficient and flexible way of returning cash to our shareholders.
Distribution to shareholders through share purchases were $20 billion in 2011. Purchases have reduced shares outstanding by over 30% since the Exxon and Mobil merger, including the impact of the shares issued for XTO. By the end of the first quarter of 2012, we expect to have repurchased the total number of shares issued to acquire XTO.
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The share purchase program continues to be an effective way to distribute value to shareholders, while at the same time maintaining flexibility to balance the cash needs of the corporation. Each share of ExxonMobil has an interest in 27% more reserves and 23% more production volumes today than it did in 2007.
Comparing these results to our competition reinforces the beneficial effect of the share purchase program for our shareholders. Since 2007, ExxonMobil has delivered annualized oil equivalent reserves per share growth of 6.1%, which is ahead of our competitors, and 5.3% annualized production per share growth, nearly 3 percentage points higher than our nearest competitor.
In summarizing, I’m pleased with our 2011 financial and operating performance across all key measures and all business lines. The results reflect the strength of our business approach and our competitive advantages. Areas of competitive advantage, which I’ll now discuss, can be found across the Upstream, the Downstream and the Chemicals. This great New York weather is giving me allergies, so bear with me.
ExxonMobil has competitive advantages that are evident across all three of our business segments. These competitive advantages serve as the foundation for our ongoing success. Within each of our businesses, the quality, the size and diversity of our resource holdings, capital projects, products and assets, uniquely position us in the industry. Our continued emphasis on discipline, selective investments from initial resource capture through project development to ongoing operations supports our ability to deliver attractive returns.
The application of proprietary high-impact technologies to our investments in operations maximizes resource value. Ongoing efforts to identify and develop new technologies that unlock previously non-commercial potential to capture new cost efficiencies, enables us to be both more efficient and more effective.
Our relentless attention to operational excellence supports safe, reliable and efficient operations. Reducing risks by applying the highest operational standards, as I indicated, is embedded in our culture.
Finally, we capture substantial value across the corporation through the global integration of our business. Within this integrated model, we have implemented processes and systems that enable our organization and investments to capture the highest value for each molecule we produce or process. I’ll highlight examples of competitive advantage in each of our business lines starting with the quality of our balanced portfolio in the Upstream.
At year-end 2011, our resource base was over 87 billion oil equivalent barrels, which is approximately 3 billion barrels higher than in 2010 after adjusting for production, asset sales and other revisions. The size and diversity of our portfolio are unmatched by competitors and offer strategic flexibility in our investment options. The chart on the left highlights the diversity of our resource base.
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Conventional oil and gas, unconventional resources and heavy oil are the largest components comprising two-thirds of our total. The balance includes acid and sour gas and oil sources, such as Kashagan, Tengiz, and Labarge, significant liquefied natural gas holdings in Qatar, Northwest Australia, and Papua New Guinea, arctic including Prudhoe Bay and Sakhalin and deepwater resources located in West Africa and the Gulf of Mexico.
Geographically, nearly 60% of our resource base is located in the Americas, with the remainder distributed around the world. Our resource base remains balanced between liquids and gas. We continue adding to these quality resources at attractive costs, as you’ll see on the next slide.
The chart on the left shows our annual resource additions over the last five years. By-the-bit additions are shown in the red portion of the bars, discovered and undeveloped additions are shown in blue, and production is shown in the dashed line. Not only have total resource additions more than replaced annual production each year, so have our by-the-bit resource additions.
Last year, ExxonMobil added 2.3 billion oil equivalent barrels by-the-bit and 1.6 billion oil equivalent barrels of discovered, undeveloped resources. The chart on the right shows our average finding costs in red bars as compared to our competitors in timeframes provided in their previous analyst briefings. We continue to outpace competition in finding quality resources at attractive cost. Let’s now look at our liquid and gas position.
This slide describes our liquids portfolio, comprised of already developed and producing operations and future resource development projects. As shown in the chart on the left, our liquids resource base is over 42 billion barrels, including over 12 billion barrels of proved reserves. Our liquids resource base is diverse, with 43% in heavy oil and oil sands, predominantly in North America.
24% of our liquid resource base is in conventional opportunities, which form the base of our business. The remaining resources are split between deepwater, acid and sour gas, Arctic, LNG, and unconventional. We’ll discuss specific projects that target these areas and provide strong growth potential later in the presentation.
As shown on the right, approximately 40% of our 2011 liquids volumes are categorized as long-plateau, which are large assets that maintain capacity production levels with minimal or no decline for many years. ExxonMobil’s gas portfolio includes 76 trillion cubic feet of proved reserves spanning all resource types with good access to major consuming markets and various commercial structures.
The chart on the left shows our global gas resource base by resource type, which includes sizable positions in shale gas, conventional gas, LNG, tight gas, and other resources. We have secured meaningful holdings of unconventional gas with significant growth potential, which will position ExxonMobil to participate in the demand growth anticipated in our Energy Outlook.
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The chart on the right shows the markets where our natural gas is currently sold, which includes a strong presence in Europe, the Americas, Asia, and the Middle East. Geographic as well as contract mix provides us with flexibility and market optionality, as shown in more detail on this next slide.
ExxonMobil holds a significant commercial presence through a wide range of gas contracts, which provide opportunities to maximize the value of our substantial global gas position. The chart on the left shows 2011 oil and gas production and 2015 estimated production, with liquids production growing from 51% of the total in 2011 to 53% in 2015.
As the chart on the right illustrates, approximately a quarter of our gas volume is sold under contracts that have some type of linkage to oil prices. Including these gas volumes, about two thirds of our total oil and gas production is linked to oil pricing.
In addition to a strong resource base we have an attractive suite of new growth opportunities. We have a growing portfolio of high quality opportunities across all resource types and a wide variety of geographies. This map shows our portfolio which includes unconventional resource opportunities in orange, new play tests in frontier basins in yellow, conventional discovered undeveloped in purple, and established basins in green.
The result is a diverse portfolio balanced between risk and resource type. We’ll discuss additional details in our exploration program shortly, but for now let’s review components of our Downstream portfolio.
ExxonMobil is the largest global integrated refiner, and our refineries are on average 60% larger than the industry. Additionally, our level of integration is unmatched with more than 75% of our refineries integrated with chemicals or lube operations.
These scale and integration advantages provide opportunities to improve profitability in our Downstream business. For example, our refineries are among the most efficient in their respective geographies as a result of continuous improvement to cost efficiencies, circuit optimization and reliable operations.
We also capture significant value through feed flexibility enabled by molecular-level analysis, capital investments and proprietary technology advantages. The lubricants business is another element of our global Downstream portfolio which remains well-positioned to meet evolving global demand, and we’ll cover in the next slide.
As I mentioned earlier, we anticipate strong growth in the lubricants demand with significant growth in the synthetics sector, which is growing at a rate of 6% per year. We are the world’s largest lube basestock manufacturer and the leading marketer of synthetic lubricants. As shown on the graph, we have three times more basestock market share and more than twice the synthetics lubes market share than the competitors’ average.
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We are also well-positioned to capture growth. In the high value finished lubricant sector we have achieved considerable sales growth due to our focus on synthetic oils including our high performance engine oils, such as Mobil 1, and our industrial oils. We continue to grow these brands and have captured significantly higher sales growth than the industry through differentiated products and engineering expertise.
In 2011, we set record sales for Mobil 1, Mobil SHC and Mobil Delvac 1. We continue to expand and extend the competitive advantage in our lubricants business by deploying advanced lubricant solutions, leading edge product technology, and growing our world-class brands.
ExxonMobil is the leading marketer and supplier of transportation fuels to a diverse set of business segments and industries. Our reach is global with fuels marketing in over 50 countries and our lubricants brands are sold in more than 100 countries. Our sales channels for transportation fuels are diverse and include retail, which is well known with our Exxon, Mobil and Esso brands.
Our three business-to-business segments include industrial wholesale, marine, and aviation. And together these segments make up over 50% of total fuels marketing sales. High quality products coupled with a strong refining and distribution network position us as a trusted, sought after and reliable supplier to a wide variety of customers around the world.
Let’s now take a look at the Chemical business. Our unique Chemical portfolio, developed primarily through organic growth, captures the benefits of scale from commodity chemicals while maximizing the value of specialty chemicals. We pursue product lines where we have competitive advantage and have developed a strong position in the markets we serve. Our Chemical facilities are strategically located around the world enabling us to supply all major growth regions from our cost competitive assets.
High volume commodities, shown in red, capture upside earnings where industry margins are strong. Specialties, shown in blue, provide a stable yet growing earnings base that in 2011 delivered a record $1.8 billion in earnings, over triple the level of only 10 years ago. Specialty chemicals are produced on a lower cost structure from the same integrated sites as our commodity chemicals.
Underpinning the success of our portfolio is the application of proprietary technology in areas of advantaged feedstock, lower cost manufacturing, and the development of new premium products. We’ll discuss more on this in later slides.
ExxonMobil’s asset holdings reflect a history of disciplined investment to deliver maximum value to the shareholders. Our disciplined investment processes delivered an efficient and productive capital base. Let’s start with the Upstream.
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ExxonMobil has a large geographically diverse inventory of more than 120 projects that are expected to develop more than 23 billion net oil equivalent barrels spanning a wide range of resource types, as shown on the chart. Utilizing our proven approach to resource development built on a disciplined gated process, our experienced global project teams closely manage our entire portfolio from discovery to start up.
Constant technology enhancements allow us to develop innovative solutions that continue to improve safety and deliver projects with attractive unit development cost to maximize the value of the investment over the entire life of the resource. The diversity and scale of our project portfolio provide ExxonMobil the ability to selectively invest in projects that deliver robust financial performance and profitable volume growth over a broad range of economic conditions.
Next, we’ll look at some of the projects we expect to start up in the next few years. This slide shows 8 of the 21 major projects that we plan to start between 2012 to 2013. In 2012 and 2013, we expect to start up nine major projects, seven of which are liquids projects including four in West Africa, Kashagan Phase 1 in Kazakhstan and the Kearl Oil Sands Project in Canada.
In 2014, 12 projects are expected to come online, seven of which are liquids projects including Arkutun-Dagi in Russia, Nabiye in Canada and Banyu Urip in Indonesia. These projects provide future production growth.
This chart shows the projected increase in net production from project startups over the next five years. We anticipate adding over 1 million barrels net equivalent per day by the year 2016. As shown on the chart in the blue shading, 80% of these new additions are liquid volumes, many of which contribute to a buildup in long-plateau volumes.
Let’s now take a look now at investments in the Downstream business. Investments in the Downstream are directed at projects that produce more high-value products including diesel, lubricants and chemicals. These investments are expected to position our refining sites for long-term competitiveness. As reflected in our Energy Outlook, we do see significantly more growth in diesel versus gasoline as the transportation energy mix changes.
Over the past five years, we have invested nearly $2 billion to increase the supply of ultra-low sulfur diesel in response to the long-term demand growth. And in 2011, as a result, we delivered record high production of ultra-low sulfur diesel.
Additionally, we recently completed a large project at our refinery in Thailand, which is expected to increase the supply of low sulfur motor fuels by more than 50,000 barrels a day. Additionally, projects are under way including new facilities as our Singapore refinery and our joint venture refinery in Saudi Arabia.
Another element of disciplined capital management is an ongoing evaluation of our existing portfolio, which we’ll discuss next. In the Downstream, we continue our ongoing and disciplined approach to extract value from our existing assets and maximize shareholder value. In 2011, we announced divestments in South and Central America as well as in Switzerland and Malaysia. And more recently, we announced plans to restructure our holdings in Japan.
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While many of our competitors characterize their own restructurings as special programs, at ExxonMobil, we’ve been high grading our portfolio on an ongoing basis for years. In fact, since 2003, we have divested our interests in 11 refineries and have fewer nonstrategic pipelines and distribution terminals. We’ve exited 65 countries and territories. We have also sold thousands of retail sites, and our conversion to a more efficient branded wholesaler business model here in the United States should be complete later this year.
Our restructuring activities have provided a material reduction in Downstream capital employed and have improved returns. Since 2003, divestments have reduced capital employed by more than 20% and contributed nearly 5% to Downstream ROCE. These divestment efforts have also generated significant cash for the corporation with little impact to underlying earnings.
Let’s look now at our major investment at the Singapore chemical facility. At our Singapore site, the largest expansion in our Chemical company history is nearing completion. The expansion establishes a world scale integrated platform with unparalleled feedstock flexibility to meet Asia Pacific demand, which as you heard earlier, we expect to drive two-thirds of global demand growth over the next three decades. We are adding 2.6 million tons per year of finished product capacity while applying leading technologies.
The project is 98% mechanically complete, and units have been progressively starting up with product qualifications under way. In January, we reached the milestone of producing our first metallocene polymer in Asia. We anticipate that commissioning and startup activities will continue throughout 2012.
While the capacity additions to our Chemical portfolio are significant, the near term earnings contribution, of course, will be dependent upon Asia Pacific commodity chemical margins, which are currently near the bottom of the cycle. With its technology and integration advantages, the Singapore site is well-positioned to outperform competition throughout that cycle. We expect value capture to accelerate as the global economy strengthens and with it the demand for our products in the region.
As I have already referenced, high-impact technologies enable advantages across each business line. And I’ll start by providing an overview of our world-class corporate research and development organization. At ExxonMobil, we recognize that the world’s growing energy needs will require technology breakthroughs to unlock potential new energy resources.
Advances in technology will continue to reshape the world’s energy landscape. That is why we have maintained active research in fundamental science to discover innovative approaches to safely and economically develop both existing and next generation energy sources. We spend approximately $1 billion dollars per year on research and technology developments and have over 10,000 active issued patents.
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Our Corporate Strategic Research Laboratory, or CSR, differentiates us among our competitors. With world-class scientific research capabilities, CSR takes a unique approach in solving tough energy challenges. Staffed with over 170 PhD scientists and engineers, their investigations into fundamental science create breakthrough technology opportunities that do deliver competitive advantages through our business lines.
These scientists and engineers collaborate with leading academics from around the world and participate in joint industry research to not only remain at the cutting edge, but to also influence the pace of scientific advancement in our industry. This work serves as the foundation for technology development within each of our three business lines. CSR not only provides early stage technology leads, but also works to solve the most complex problems confronting our businesses.
Examples of how this research provides a solution on a commercial scale are shown on the left. From solving Arctic environment metallurgy challenges at the atomic level, to developing state-of-the art analytical technology to understand the molecular composition of crude oil, this knowledge is used to maximize the value extracted from every molecule.
Next, I’ll describe some of our technology development at the business level, starting with the Upstream. Our long-term commitment to research continues to deliver advantaged technologies in our Upstream business. Technology plays a part in all aspects of the business from exploration through development and production.
In exploration, we are continuing to focus on discerning subsurface images that cannot be visualized today. For example, in the high end seismic processing technology, we have recently received patents for our simultaneous source Full Wavefield Inversion technology which allows unprecedented imaging and construct of models of subsurface reservoirs.
In drilling we are developing techniques to keep bore holes clean, stable, and smooth by removing cuttings faster and more efficiently. This research, when deployed in combination with our proprietary Fast Drill technology, further increases drilling speed which reduces cost as well as extends our ability to drill the world’s longest reach horizontal wells.
Our horizontal Just-in-Time Perforation technology enables us to fracture multiple intervals in a well in less time with greater selectivity, reducing cost, increasing production and recovery, and reducing water usage — an example of how these technologies deliver value.
ExxonMobil has a record of successful developments in challenging conditions and a suite of patented technologies that allow us to continue to be the industry leader in extended reach drilling. We have drilled 23 of the 27 longest reach wells in the world. This includes drilling the world’s longest reach and longest measured depth well at our Sakhalin 1 development last year.
Our integrated technologies provide uplift across the full value chain from early modeling and wellbore planning to patented and proprietary technologies that enable the safe drilling and completion of these record length wells. Not only does this technology enable access to hard-to-reach reserves, it also reduces our environmental footprint for the development of an oil and gas field, and it certainly increases our capital efficiency.
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Now, let’s look at how technology provides differentiation in the Downstream. In the Downstream, margin improvement remains a key strategic priority and advantaged technologies enable us to improve performance in this area. We continue to improve margins by focusing on reducing raw material cost, increasing utilization, and capturing high product realizations.
We reduce raw material costs by upgrading our facilities and applying innovative technology to expand processing flexibility. For example, our advanced modeling and characterization tools enable challenging new feeds to be selected for processing. As shown on the graph, we lead industry in our ability to run discounted, challenged crudes, running 50% more on our crude slate than industry average, due largely to these technologies.
Additionally, to expand our ability to handle a wide variety of feedstocks, we are developing proprietary heavy oil characterization technology that will allow us to more effectively process heavier feeds at our refining sites. We maximize the economic utilization of our existing refining capacity by improving reliability, eliminating operating constraints and expanding market outlets.
Robust systems and supply chain models help us place molecules in the right place and at the right time to improve margins. In 2011, our U.S. refining utilization was 91%, an improvement versus 2010 and better than the industry average. We’ve continued to capture higher product realizations, as I mentioned earlier, with record ultra-low sulfur diesel production and record sales of our high value synthetic lubricants in 2011.
We’ll look now at how technology provides advantages to our Chemical business. Our Chemical business leverages proprietary technology to gain advantages processing both heavy and light chemical feedstocks. From the red bars in the chart, you can see that a much larger proportion of our feedstocks are advantaged compared to industry average.
This is a result of three factors. First, our facilities are configured to run a wide range of feedstocks due to the application of proprietary technology in both the design of the facilities and the operation. Second, because of our logistics and our integration with refining and lubes, we have access to a variety of feedstock streams, allowing us to select the ones that are advantaged at any point in time. These two factors help us to maximize low cost ethane use in 2011.
And third, we have molecule management tools that enable real-time re-optimization of process flows. And our close integration with refining provides alternate placement for byproduct streams. We continually evaluate opportunities to expand our feedstock advantage, including options to enhance our industry-leading capability to process light feedstocks in the United States.
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In both our Downstream and Chemical businesses, we use analytical and modeling capabilities to generate molecular level understanding of our products and develop leading edge technologies to improve product properties and applications. We employ fundamental models that help us understand how each molecule can be best utilized to produce high value products.
These models also enable development of advanced catalysts and processes to efficiently upgrade a wide variety of crudes into a wide range of products. For example, we have several active programs focused on providing significant fuel economy benefits in our flagship Mobil 1 products while maintaining outstanding engine protection and lower emissions.
We also pursue technology breakthroughs such as our metallocene catalysts which are used to manufacture premium chemical products for a wide range of applications, including flexible packaging, consumer products and lubricants.
These products deliver benefits to customers that include reduced raw material cost, improved performance and energy efficiency. Research on our fuel products also continues to improve that product quality. For example, we recently reformulated our gasolines in the United States to help improve engine cleanliness.
In addition to our emphasis on technology, we view our relentless pursuit of operational excellence as another advantage. We know that operational excellence begins with exceptional employees. Our talented workforce, backed by rigorous management systems, forms a strong foundation for operational excellence.
We’re proud of the culture of excellence that is instilled in all of our employees around the world, as well as the contractors that work for us. It is a culture of doing the right thing and not accepting comprises to our values. All of our employees receive specialized training, which is designed to incorporate decades of best practices that have been developed across all of our businesses.
Employees have access to the breadth and depth of experiences of employees in similar positions across the world. Our employees also receive diverse experiences and assignments enabled by our global functional organizational model, which encourages sharing of information and talent.
Our goal is to position employees for a long-term career so that they can continue to grow and contribute to our strong experience base, as well as develop into our next generation of leaders. Another important aspect of our workforce development is to hire and build the skills of nationals in developing countries where we operate.
We’ll take a look now at how operational excellence in the Upstream provides a competitive advantage in cost and reliability. A focus on reliability and cost management is an integral part of ExxonMobil’s operations and it is important — an important component in maximizing the resource value.
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Our historically strong reliability and cost performance is driven by rigorous management systems within our global functional structure, which allows quick and effective sharing of best practices and technical expertise around the world.
Our reliability performance over the last five years has been quite good with operated uptime over 3 percentage points higher at ExxonMobil-operated assets compared to fields operated by others in which we hold an interest. This is the equivalent to about 41,000 oil equivalent barrels per day of additional production.
A key component to our reliability performance has been maintaining the integrity of our facilities by managing critical equipment performance over the entire lifecycle. Strong reliability not only leads to safe operations, but helps to drive superior profitability as well.
Our disciplined global operating and maintenance systems will continue to help us deliver strong reliability and cost management performance. Rigorous high quality project management underpins our proven project execution.
The chart on the left shows the average variance between the actual and funded costs for projects started up between 2007 and 2011. The red bar represents ExxonMobil-operated projects and the blue bar reflects ExxonMobil projects that are operated by others.
Over the last five years, we have delivered operated projects on average within 3% of funded costs, while similar projects operated by others were on average 9% above budget. Decades of project management experience, combined with a comprehensive suite of processes and tools, helps to drive superior costs and scheduled delivery.
Also, by maximizing project efficiencies, we are able to deliver comparable projects at a lower cost, and faster than our competitors. The reappraisal of all major projects, we are constantly incorporating learnings into future project planning and design, further strengthening our capabilities.
ExxonMobil’s ability to maximize the value of each asset is also the result of our disciplined and consistent approach to cost management. One way we do this is by employing global contracting strategies and applying best practices in our global operations. And as I have mentioned, we continuously highgrade the asset portfolio.
Our approach to operational excellence has served us well, and we continue to outperform most of our peer group on total cost per unit of production. The next slide highlights an example of how operational excellence results in differentiating performance.
Our Angola and Sakhalin developments are examples of how quality resources and differentiating technologies, combined with project and operational excellence, delivers significant lifecycle value. In Angola we have produced over 1.4 billion oil equivalent barrels since the first — with the first production of Kizomba C beginning 23 months after sanction, which was a record in 2008.
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The application of our “Design One Build Multiple” approach has significantly reduced project costs over time and has since been adopted by many of our competitors. In Sakhalin, we have produced over 340 million barrels of oil and set a record for drilling the longest extended reach well in the world. We are continuing to push the boundaries to economically develop the remaining reserves.
In both frontier areas, we have been able to achieve over 95% uptime due to applying best practices as discussed previously. This is especially impressive at Sakhalin, considering the very harsh environment. A key element of our success has been the rapid nationalization of the local workforce, which today exceeds 75%.
This success in Angola and Sakhalin would not have been possible without a strong partnership with the host governments and our partner national oil companies. The success in Angola, our long-term full-cycle approach, combined with operational excellence delivers significant value. Let’s now look at the operational excellence benefits delivered in the Downstream.
As this chart shows, our Downstream business has become ever more efficient. Since 2004, ongoing efforts to optimize our supply chain have resulted in significant improvements, including the streamlining of products by over 40% and the consolidation of order centers and the rationalization to blend plants by 50%.
We’ve made these changes while maintaining strong sales levels and growing high value products. Ongoing improvements in productivity are expected to continue with the recently announced consolidation of our fuels and lubricants marketing businesses.
We have achieved additional efficiencies and improved productivity across the Downstream by moving to consistent global processes, including centralization of support activities, innovative technologies, and investments in work processes and systems.
We also work diligently to maintain and grow our cost advantage in our Downstream and Chemical manufacturing operations. In the area of efficient energy use, our refining and chemical plants continue to outperform the industry. Since energy is the largest component of cash cost for refineries, improving overall energy efficiency in our operations is a must.
As you can see on this chart, our refining energy intensity continues to decline. In 2011, we had our lowest ever energy use across our global refining circuit. We’ve grown our advantage over industry not only in refining operations, but also in our Chemical steam cracking operations.
By leveraging integration synergies between our refineries and our chemical plants, implementing globally shared best practices, and applying advanced technologies, we have captured significant cost efficiencies. Our Global Energy Management System and continued investments in cogeneration capacity are also helping our manufacturing sites become more efficient.
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Our strategies and execution have also enabled our Chemical assets to be more productive. In the chart you can see a comparison of the five-year average steam cracker utilizations for ExxonMobil and for the rest of industry, with ExxonMobil operating 2 percentage points higher.
Reliability is a critical focus area, with rigorous root cause analysis, equipment strategies and loss monitoring. The feedstock flexibility I mentioned earlier generates additional advantage by expanding the range of conditions where steam cracker operation is attractive.
We pioneered steam cracking in 1941 and since then we have taken a — we have been a technology leader through extensive operational experience and broad fundamental research and development. Additionally, our premium and specialty products are in higher demand than competitor offerings, which keeps our steam crackers running full.
Next we’ll look at our ability to effectively implement integration across our business globally to capture advantages. The effective and efficient implementation of our integrated business model allows ExxonMobil to capture significant value across our holdings from the Upstream, throughout the supply chain at our manufacturing sites, all the way to finished products.
We leverage our global functional organization to implement best practices around the world and across business lines, which allows us to apply the highest standards in areas such as risk management and operational excellence. Also, integration provides efficiency due to scale, shared support services and purchasing power.
And finally, we’re able to develop and deploy new technologies that have application across multiple business lines, which maximizes the value from our proprietary technology. Integration also allows us to maximize benefit across the value chain, as I’ll discuss on the next slide.
A good example of this, the value to our integrated model is in the Upstream project development. We effectively leverage our Downstream technical expertise and global marketing presence, as well as refining and logistic assets, to enhance resource value during the early stages of Upstream project development. We have developed systems and trained personnel specifically to facilitate this early integration to enhance the eventual marketing and valuation of new crude and condensate resources.
Additionally, we use an integrated approach to optimize fiscal and commercial terms and to develop market outlets for new crudes. Through technology we can expedite crude assay and characterization development to help identify challenging crude properties that could impact refining. And with our large and flexible refining and logistics network, our Downstream is able to provide back-stop processing capabilities.
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A recent example of our successful and ongoing Upstream/Downstream integration is our Kearl Oil Sands Project. Our global supply organization has a broad understanding of the marketing options for new crudes while our refining and technology optimizations have the technical knowledge to optimize processing of this important new resource. This early integration across our supply chain enhances overall resource value as we will solve many of the challenges prior to startup.
Next, let’s look at integration at our manufacturing sites. Over 75% of our refining capacity is integrated with chemicals or lubes, and over 90% of our Chemical capacity that is owned and operated is integrated with our large refineries or our natural gas processing plants.
At our integrated refining and chemical sites, we use optimization tools that help us decide in real-time whether molecules should be made into fuel product, lubricant basestock or sent to neighboring chemical facilities as feedstock for higher value chemical production. Using proprietary technology, we have engineered flexibility into our assets so that they can run a wide range of feedstocks, which help us reduce operating costs and increase margins.
We also utilize common site management, utilities and infrastructure. Common global processes and a global functional organization help us capture the value of integration by deploying best practices quickly and efficiently. Our global scale and leverage of integration are structural advantages that are difficult for competitors to replicate, resulting in our continued industry-leading returns.
The integration benefit ExxonMobil achieves throughout the business cycle we believe are unparalleled, as can be seen in our combined Downstream and Chemical return on capital employed performance. Our proven business strategies and global integration have enabled our Downstream and Chemical businesses to generate significant shareholder value.
From 2008 to 2011, these businesses had combined average earnings of $8 billion per year. And as shown on the chart in red, they had a combined average return on capital employed of over 19%, nearly three times higher than the competitive average. These results clearly demonstrate the unqualified benefits we achieve through the integration of our Downstream and Chemical platforms.
In closing, the unique competitive advantages we possess lead to exceptional performance in each of our business lines and serve as the foundation for the creation of long-term shareholder value.
I’ll now turn it back to David to review the remaining agenda.
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David Rosenthal
Thank you, Rex. At this point we’d like to take a quick break. I would like to limit it to about 10 minutes. And then afterwards, we will continue the discussion with Mark Albers and Andy Swiger providing a more in-depth discussion of the Upstream business. So please, let’s plan to be back and ready to go at 10:35. Thank you.
BREAK
It is 10.35 am, so if I could ask everyone to take their seat. If I gave you 15, they’d take 20. All right we’d like to get started. If everybody could find their seats. All right as I mentioned earlier, the next part of the program we’re going to take a more in-depth look at our Upstream business. And to start it off I will turn it over to Mark Albers. Mark.
Mark Albers (Senior Vice President)
Thank you, David. Good morning everyone. In the next 30 minutes or so, Andy and I will give you a little deeper dive into ExxonMobil’s Upstream business. Let’s begin on this next slide with our fundamental approach.
This chart summarizes the core strategies that underpin our results. They reflect the long-term nature of our business, and while they’re not probably unique in industry and certainly not new to you all, I think what differentiates us is in the execution. The differentiation also comes in how we assess and manage business and operational risk. It drives where we enter, how we enter, and how we operate for the long term.
We’ll begin, as you look on the right, with identifying and securing a material position in the highest quality resource by resource type. We pursue attractive fiscal and commercial terms that includes, of course, getting in early and negotiating a premium for the value that we bring, as well as building effective partnerships with host governments and national oil companies. We apply distinguishing technologies, as Rex showed you, to achieve the lowest lifecycle cost. We then execute that plan in the most cost efficient and cost effective manner.
Over the life of the resource, our relentless focus on operational excellence delivers maximum value and responsible development. And in the end, our objective is to deliver industry-leading returns over the long term and of course provide the greatest value to shareholders.
There’s a lot on this chart so let me just step you through it. As Rex indicated, the Energy Outlook really provides the basis for our view for the demand for our resources. The chart on the left represents the various resource types and the volumes that are required to meet demand out to 2040.
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Beginning on the far left, the conventional supply is of course very large in absolute terms and its projected growth is on top of a large declining base. To put this in perspective, in 2040, 40 million barrels per day of conventional liquids production will be from fields that are not yet developed, and that’s the equivalent of four Saudi Arabia’s.
Not surprisingly, the fastest growth segments include the unconventional and the heavy oil resources. If you look on the right, you’ll see ExxonMobil’s resource base and as you can see we’ve got a very large, material position in all the resource types. But in particular those types are going to have a lot of demand as we view the global Energy Outlook. Maintaining a quality material position in each resource type is really a key enabler. That’s where it all begins.
But when you combine that with technology and operational capabilities, even greater value can be unlocked, and Andy and I are going take you through several examples of that beginning with the conventional resources.
Our conventional resources deliver significant value and provide, of course, a very solid foundation for future profitable growth. In our legacy assets, we’re applying global best practices and operational excellence to identify new development opportunities all the time.
For example, at the Balder and Ringhorne fields in Norway, 40 seismic and enhanced drilling capabilities are significantly extending the life of these fields, increasing remaining reserves by a third. As shown by the blue dots, major development projects for conventional resources are under way around the globe. And I’ll highlight a few of them now, and we’ll speak to a few of them later.
Beginning in Iraq, the redevelopment of the West Qurna-1 field is progressing well, with production capacity of 390,000 barrels per day, up more than 145,000 barrels per day from the start or up 60%. Planning is under way to add further well capacity and production facility capacity, and additionally, we’ve got seismic planned this year.
At Upper Zakum in the UAE, we continue to progress the expansion project to boost production capacity from about 550,000 barrels a day to 750,000 barrels a day. We’re using an innovative artificial island approach coupled with very long extended reach wells to not only reduce the environmental and facility footprint but increase recovery. Construction is under way on the artificial island and extended reach drilling is expected to commence around mid-year.
In Vietnam, we made a material gas discovery in the second half of last year, and we have additional drilling planned for this summer. We also made two discoveries, one oil and one gas, in Indonesia near our Banyu Urip development.
As you look to the future, we signed the Strategic Cooperation Agreement with Rosneft, covering 31 million acres in the Kara Sea, and I’ll have more to say about that in a moment. As you know, in 2011, we signed six production sharing contracts in the Kurdistan region of Iraq, with a total license area of 848,000 acres.
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Next, I’ll give you a little update on one of the near term major developments, which is Banyu Urip. Banyu Urip is an onshore, 450-million barrel oil development. In 2009, early oil production accelerated value capture.
Full field capacity is 165,000 barrels per day, and the development includes an onshore central processing facility and an offshore floating storage and offloading vessel. We’ve now ordered all the major engineering procurement and construction contracts and full field development is progressing on schedule. We’ll start up in 2014.
Now, let’s look at our Arctic resources. In Russia, Sakhalin 1 is producing approximately 150,000 barrels per day. The Sakhalin project has set and broken its own world records for the longest extended reach well, including the most recent well in Odoptu with an extended reach of 7.1 miles. World-class extended reach drilling has been a key enabler in the development of this resource. We’re now applying this proven capability to progress additional developments in Sakhalin.
At Arkutun-Dagi, which is the next phase of Sakhalin 1, we have completed construction of the gravity-based structure and we’ll float that out later this year. We’ve also commenced topside fabrication. Arkutun-Dagi will have a peak production capacity of 90,000 barrels a day and is on schedule to start up in 2014.
In Eastern Canada, the Hebron project, which includes a gravity-based structure, topsides facilities and drill rig, is progressing with front end engineering under way and full funding expected in the next 12 months.
Now let’s look a little closer at our Arctic opportunities in Russia. In 2011 ExxonMobil and Rosneft signed a Strategic Cooperation Agreement to jointly explore and develop hydrocarbon resources. This agreement includes a total of 31 million acres in three blocks as you see in the map. To put that in perspective, that’s equivalent in size to all of the leased acreage in the Gulf of Mexico.
As you can see from the map, from the brownfield locations, it’s an extension of the existing very prolific West Siberian oil basin. This has very high prospectivity for both liquids and gas. We’re currently progressing the definitive agreements and pursuing the fiscal improvements that are needed to move us into the next phase.
Exploration activities will commence this year with 2-D and 3-D seismic, and drilling will commence in the 2014, 2015 timeframe. ExxonMobil continues to advance new Arctic technology solutions we think was a key enabler in the Rosneft Strategic Cooperation Agreement.
But we’ve been at this a long time. We’ve been working at this for over 90 years and we’re currently focusing our research efforts on the next generation of technologies that will be needed. For example, we’re advancing capabilities to accurately characterize surrounding ice and predict its movement, which will facilitate real-time operational decisions. We’re working to extend the drilling season beyond the available open water season.
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To address this challenge, ExxonMobil is developing new concepts in floating drilling, subsea production, offshore loading, and extending the application of gravity-based structures and subsea structures.
This suite of technologies will provide ExxonMobil really a competitive advantage in safely and responsibly developing resources in the most challenging Arctic environments on the planet. This is a distinguishing capability as the Arctic remains one of the most under-explored highest potential areas in the world.
Now let’s move to the deepwater resource. ExxonMobil has established a proven deepwater capability from exploration through development through production. Our innovative design approach in Angola and Nigeria and Equatorial Guinea led to significantly reduced costs and accelerated field startups.
Recently we’ve also applied innovated technologies to develop satellite fields through subsea tie-backs at existing facilities such as the Kizomba fields in Angola. And we’re also applying this in the Gulf of Mexico.
Our deepwater exploration program has been quite active. This year we are drilling wells in Nigeria, Tanzania, Romania, and the Romanian Black Sea and the Gulf of Mexico. These opportunities include established basins with proven hydrocarbon systems as well as new play tests.
We think this approach balances the risk while providing significant exposure to upside potential. In that regard, our recent Tanzania wildcat encountered significant hydrocarbon resources in very high quality reservoir sands. We and our partner Statoil are planning to drill a follow-up well to test a second prospect on the block.
In Romania, in the Black Sea, we were also recently successful with a new play test in the deepwater. Additional follow-up drilling is planned once we acquire and assess additional 3-D seismic on the block.
The Gulf of Mexico has also been a highlight. It continues to be an active area as we progress appraisal and development of our recent discoveries. We hold a large, high quality position of about 1.3 million acres. Four recent discoveries include Hadrian South, Hadrian North, Lucius and Julia. The discoveries on our Hadrian blocks are among the most significant discoveries in the Gulf of Mexico in the last 10 years.
Hadrian South is a subsea gas development which will be tied-back to the Lucius facility. The project was fully funded in 2011 and we expect startup in 2014. Hadrian North will be a 100,000 barrel per day capacity development with a new build, semi-submersible floating production system. We have appraisal drilling planned this summer and FEED is under way. We have a 50% working interest in Hadrian North.
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As shown in the lower left, the Lucius and Hadrian developments have among the lowest unit development costs of current Gulf of Mexico deepwater projects, supported by a recent Wood Mackenzie study. The Julia structure contains a significant resource in the geologically challenging Walker Ridge area. Development will be conducted in a phased approach to capture and integrate learnings on subsequent phases.
The initial phase is expected to produce about 190 million barrels of oil through a subsea tie-back to the Jack St. Malo facility. Front end engineering and design are under way. And we have a 50% interest and operate Julia.
On our exploration acreage, we continue to grow and mature the prospect inventory to be in a position to routinely drill a number of wildcats each year, and we have a number planned in the next 12 months.
Moving now to LNG, we’ve established a leading global capability here, building on over three decades of experience. Today, the operations we participate in account for 25% of the world’s LNG production with marketing and operations activities spanning the globe. Of course, this success is built on very strong partnerships with host governments and national oil companies.
In Qatar, we and Qatar Petroleum were able to successfully develop a number of emerging LNG markets. Enabling technologies, including large LNG carriers, large trains and the first offshore LNG receiving terminal helped to expand the global market.
Today, we are progressing an additional 27 million to 28 million tons per annum of new advantaged projects in Papua New Guinea and Australia. As shown by the graph on the right, the projects we and our partners are developing are also among the lowest unit development cost projects in the world. This, combined with our global gas marketing capability creates maximum resource value.
Now, let’s take a little closer look at the PNG project. In Papua New Guinea we are developing a high quality 9 trillion cubic foot gas resource. The project includes a two train, 6.6 million ton per annum LNG plant near Port Moresby, as well as a 430-mile pipeline to transport the gas. All the major contracts have been awarded, and the project is on schedule for startup in 2014.
Just to give you a little bit of an update, recent milestones include completion of about half of the offshore pipeline. We’ve begun installation of pipe racks and tank foundations at the LNG site. We also have a very active exploration program with two wells planned this year and additional seismic. And this activity is designed to support expansion studies for a third train.
So with that I’d like to introduce Andy, who will speak to our unconventional resources.
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Andy Swiger (Senior Vice President)
Thank you, Mark. In addition to our substantial conventional, deepwater, and LNG resources, our resource base also includes an industry leading 38 billion oil equivalent barrels of unconventional resources, which is more than double the 2005 year-end levels. And it reflects our expanding position in the two supply areas we project to have the strongest global growth over the coming decades, heavy oil and oil sands and unconventional oil and gas.
Overall, our unconventional resources increased 10% in the year 2011 and account for more than 40% of ExxonMobil’s total resource base. Our unconventional resource base remains balanced between quality resources in heavy oil and oil sands, and unconventional oil and gas. We have a deep inventory of attractive opportunities including over 50,000 drilling locations.
Let’s now take a look at the distribution of our North American unconventional acreage position. We hold a material position in multiple unconventional plays across North America totaling 8 million acres. In Canada, our stake in the Athabasca oil sands is anchored by the Kearl project. We also have strong positions in the Horn River gas play, the Summit Creek area, and in the tight oil reservoirs of the Cardium oil play.
In the U.S. we have a substantial position across the spectrum of unconventional play types, and we are increasing our leasehold in emerging liquids rich plays like the Woodford Ardmore, the Utica, the Smackover Brown Dense Limestone, and those in the Permian Basin.
Now let’s take a closer look at our oil sands resources and activity. ExxonMobil holds advantaged, high quality oil sands resources which are well-positioned to deliver long-term value. The chart here illustrates the superior quality of our Kearl and Firebag resources relative to other undeveloped oil sands mines in Western Canada. As you can see, both have high quality ore grade and a low ratio of material moved to bitumen in place.
To put this in perspective, the operators represented by the two dots in the lower left corner of the chart will need to mine approximately one and a half, 1.5 times more material than Kearl in order to produce a barrel of bitumen.
Since moving material is one of the most significant factors in determining unit capital and operating costs, Kearl will have advantaged unit costs relative to other new oil sands mines. Given the quality and materiality of these resources, oil sands are an important growth area and will deliver long-plateau volumes.
Now, let’s take a closer look at our Kearl Development. Kearl will access 4.6 billion barrels of resource providing a long-term plateau production profile. The Kearl initial development is 88% complete and progressing on schedule to commence operations by year-end 2012. Production rates are expected to be 110,000 barrels of bitumen per day.
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As the second step of the phased Kearl Oil Sands development, the Kearl Expansion Project has been fully funded and will bring on an additional 110,000 barrels of bitumen per day by late 2015.
The expansion project will employ our successful “Design One Build Multiple” approach, whereby 90% of the initial development engineering will be reused in this development. With future debottlenecking plans, which will be based on actual operating experience, the long-plateau volumes are expected to reach Kearl’s regulatory production limit of 345,000 barrels of bitumen per day. Kearl is the first oil sands mining operation without an upgrader.
Our proprietary paraffinic froth treatment technology enables us to decouple mined oil sands bitumen production from upgrading by producing a diluted bitumen similar to in situ projects, that meets pipeline and refinery specifications. The technology eliminates the need for an onsite upgrader, which avoids a multi-billion dollar capital investment and its associated operating expense.
And by processing the oil only once in a refinery, instead of in an upgrader and a refinery, Kearl’s full-cycle greenhouse gas emissions will be similar to many other crude oils processed in the United States. By combining this high quality resource with our proprietary technologies, proven project execution capability and operational excellence, we project that Kearl will be one of the lowest unit cost oil sands mining projects in the industry and provide attractive returns over the long term.
ExxonMobil is progressing new emerging technologies to further unlock oil sands value, with paraffinic froth treatment as just one example. We are advancing technologies to enhance tailings deposition processes with the scale of the Kearl operation, which will result in reduced handling costs and accelerate land reclamation.
We’re also developing a game changing oil sands extraction technology. This technology which we call Non-Aqueous Extraction or NAE, uses a hydrocarbon solvent instead of water to separate bitumen and sand. NAE has to the potential to significantly reduce fresh water use, eliminate new wet tailings ponds and increase recovery. As you can see, these emerging technologies will allow us to further unlock oil sands resource value.
Moving now to unconventional gas, new technology and advances in production techniques have unlocked close to a century’s worth of natural gas in the United States. Given all material North American unconventional portfolio, ExxonMobil is well-positioned to continue to create value in this area. Unconventional production is expected to grow as conventional sources decline and natural gas gains advantage as a competitive alternative to coal.
In North America, our outlook is that overall demand for natural gas will grow at slightly more than 1% per year on average over the next couple of decades. With the expected continued decline in conventional supplies, local unconventional gas production will grow at an average annual rate of over 4% per annum to meet this demand and will account for more than 70% of demand in 2030 versus about 40% in 2010.
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We are focusing on continuing to capture the upside potential of this North America demand growth and are in the early stages of assessing potential export operations from North America including Alaska, the Gulf Coast, and Western Canada.
The foundation of our unconventional capability and a key enabler to creating long-term global value from these resources is XTO Energy. As shown on the chart, XTO was managing 82 trillion cubic feet equivalent of resources at year-end, an increase of 81% since the acquisition. This growth has been balanced by a mix of positive performance revisions and several strategic bolt-on acquisitions at a cost of only $0.23 per 1,000 cubic feet equivalent.
The expertise behind this successful expansion of U.S. unconventional resources is now being transferred to our pursuit of global unconventional resources as we leverage XTO’s capabilities. For example, learnings from XTO’s experience in horizontal shale drilling and tight oil plays have played a key role in our successful Cardium play in Canada.
Another example is our unconventional project in the Neuquen Basin of Argentina which we’ll discuss shortly. In this play, we are drawing on XTO’s expertise in drilling, completion and long-term development in shale plays.
I’d like to now review some examples of our liquids-rich plays. ExxonMobil is well-positioned in liquids-rich unconventional plays. For example, in the Bakken Shale, liquids production increased 27% from 2010 to 2011. Currently, we are utilizing seven rigs to develop this resource as we move from delineation to development.
In the Permian Basin, exploitation continues across our legacy tight oil positions. In addition, we are evaluating unconventional potential across roughly half of our 800,000-acre leasehold. Our liquids-rich Woodford Ardmore play continues to expand with nine rigs now drilling. Our acreage position in this emerging play tripled in 2011 to over 170,000 acres. We have amassed this position at an attractive cost.
For example, our Woodford Ardmore costs for acquisitions in 2011 were roughly 50% below recent major industry acquisitions in the Eagle Ford play on a per acre basis. As shown in the lower left of this chart, the development has the potential to exceed 70,000 oil equivalent barrels per day and recover 600 million oil equivalent barrels at approximately $10 per oil equivalent barrel.
We are also continuing to build our position in a number of other emerging liquids-rich plays. In Western Canadian Cardium tight oil play, we had eight wells drilled by year-end with three online. Early results from this play are encouraging with average first month per well production of about 275 barrels per day.
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Finally, in addition to our large Marcellus-Utica position in Pennsylvania, we have over 75,000 acres in the Utica play of eastern Ohio, and we anticipate commencing our first well in the very near future.
Now look at how we are applying learnings across these plays. Operational efficiency and technology enhance unconventional value by delivering higher recoveries and lower unit development costs. In addition, transferring operational knowledge and expertise from mature plays to newer plays is a key enabler to unlocking value in our global unconventional portfolio.
One example of this is the knowledge of — one example of this knowledge transfer is shown in the chart which compares the history of drilling efficiencies in our most mature shale play, the Barnett, with two early stage shale plays, the Fayetteville and the Haynesville. In the Barnett, more than 1,600 wells drilled over the past eight years have shown a dramatic 63% improvement in drilling days per well even as the measured depth of the wells has increased by 15%.
The Fayetteville is exhibiting the same behavior across the early part of its lifecycle. Here drilling days per well have improved to 24% in to third year of drilling, even as the average measured depth in the wells has increased 8%. Likewise, in the Haynesville play, drilling days have improved by almost 25% in the third year.
To achieve these wells, we apply a systematic phased approach which involves deploying a play development model based on experience from more mature plays, optimizing drilling and completion practices, and later on, the implementation of multi-well pad drilling. We are applying this approach to our global unconventional portfolio.
Let’s now look at how new technology is further unlocking unconventional oil and gas value. On this slide, I would like to share with you one of the examples where we’ve made important progress combining ExxonMobil’s technology with XTO’s significant operational experience in unconventional plays.
The Just-in-Time Perforating, or JITP, is a technology we have developed and applied in over 300 vertical and deviated wells and more than 10,000 zones in Piceance tight gas wells. JITP allows us to fracture multiple intervals in a well in a very highly selective fashion. It’s hard to visualize this in a snapshot, so we have a short video to demonstrate how it works.
The animation will show you how we complete a well using JITP. As the clip starts, you will see a zoomed in view of a wireline gun perforating the rock formation in a horizontal well. The wireline gun fires the first set of perforations and is then positioned for subsequent perforations. Fracturing starts on the first set of perforations and then ball sealers are dropped to seal off the open perforations.
The guns are immediately fired on the second set of perforations, initiating the subsequent stimulation treatment without shutting down the pumps. The process is repeated throughout the horizontal section of the well and once the fracture stimulations stages are completed, the well is put online and produced.
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The ultimate goal of this technology is to reduce cost through reduced equipment and horsepower requirements. Furthermore, the surgical placement of fractures should provide an increase in recovery and allow for better use of the flowback water. XTO is applying this technology in the Fayetteville shale play and is evaluating the full cost reduction and production uplift potential.
Shifting now to our global unconventional portfolio, we continue to grow the global unconventional portfolio with early mover quality acreage pursuits. During the past year, we have continued to increase our efforts to not only capture new opportunities but to conduct drilling and testing operations.
In Europe, we drilled wells in Germany and Poland. Testing of the Germany wells is pending regulatory approval. The two vertical wells in Poland did not flow at commercial rates, but did provide extensive reservoir data which we continue to evaluate. We are also acquiring additional 3-D seismic data in Poland and will utilize this data to progress our overall evaluation of the play.
In Indonesia, we are using the data from our recent drilling program to assess the coal bed methane play. In China, we signed a Joint Study Agreement to evaluate the Sichuan basin shale gas potential. Technology development and application will be one of the key elements in maximizing the full value of these resources.
Now, let’s take a closer look at our activities in Argentina. We currently hold over 800,000 net acres in the Vaca Muerta play of the Neuquen Basin. Over the past year, we have been working with our partners to develop a plan to test and evaluate the play by leveraging our XTO and ExxonMobil experience. The first two wells spud in December will test the liquids and the gas potential of the play.
Let me conclude by summarizing how we have put our Upstream strategies to work. We pursue high quality resources, establish effective partnerships, develop and apply distinguishing technologies, and bring our project and operations excellence to bear to lock on significant value in the Upstream.
Unlocking this value requires a long-term view and ability to invest throughout the business cycles. To meet the world’s evolving energy needs, development of all resource types will be required. As we have shown, ExxonMobil has a diverse and material portfolio across resource types of growing importance in meeting global energy demand, and we are well-positioned to capture that value.
I will now turn the presentation back over to Rex.
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Rex Tillerson
I think I needed to plug into a battery source earlier. I want to thank Mark and Andy for their overview that they provided you on a little deeper understanding of our Upstream business.
I’d like to move on now to discussing our capital investments plans and our volumes outlook. As I mentioned before, ExxonMobil is committed to maintain the financial flexibility necessary to pursue investment opportunities we judge to be attractive through the normal ups and downs of economic and business cycles. Our projects are evaluated using a range of prices to support attractive returns under varying business conditions.
We are executing a large inventory of high quality projects. Actual spending in a given year will vary depending on the pace and the progress of each project. We are anticipating an investment profile of about $37 billion a year in 2012 through 2016, as shown in the graph.
Upstream investments, shown in blue, continue to dominate, with the 2011 bar including the Phillips acquisition. Downstream and Chemical project spending reflects ongoing investments, as I indicated earlier, to strengthen competitiveness and capture unique opportunities. These estimates represent our best view as we look to the years ahead.
Let’s now look at the Upstream production profile. Before I provide an updated volume outlook, I think it will be useful to compare our volume performance to the outlook we gave you at this time last year. The left graph is a bridge of our actual 2011 production versus the outlook provided last year at the Analyst Meeting.
Our outlook for last year was a production volume of 4.6 million oil equivalent barrels per day, which was based on a forecast of lower prices than actually realized in 2011. Adjusting for 2011 actual crude prices and the associated impacts those have on entitlement volumes, the outlook would have been about 140,000 barrels equivalent per day lower.
However, project ramp ups and positive unconventional performance exceeded our expectations, delivering 2011 actual production of 4.5 million oil equivalent barrels per day, or an increase of 1% over last year’s outlook.
On the right, using the adjustment for prices, we have recalibrated the outlook we provided you last year for annual growth for the period from 2009 to 2014. Many of you will recall we indicated production would grow between 4% and 5%, on average over this period.
The outlook was based on a more conservative price basis, but to make things simpler, we’re going to recast that outlook using the 2011 average prices, specifically $111 per barrel Brent crude price, and apply that for each of the years going forward. And I’ll let you figure out what you think the price is really going to be.
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Now, as you can see, the higher price basis does reduce the growth outlook, but that’s partly offset by additional volume growth from our updated plans, resulting in revised growth of 2% to 3% across the 2009 to 2014 period. Having provided this new projection to you, obviously, we made more money than we thought we would as well on lower volumes.
We will still use a more conservative basis as we make our investment decisions, again, to maintain that discipline to ensure we’re investing in opportunities that will perform well across a range of prices.
This next chart shows the total Upstream production outlook through 2016 on that same basis that I just described to you. Our continued focus on reliable operational performance and new high quality projects expected to startup, volumes continue to grow throughout the period.
Of course, the actual production in any specific year can vary above or below what is reflected here due to these variables that we’ve talked about, such as price, quotas, divestments, weather, regulatory changes, and certainly geopolitical events. But with that understanding and on that basis, and again, applying the 2011 average prices during the timeframe shown, we expect continued volume growth over the period.
The outlook for 2012 reflects a potential decline of 3% from last year if crude prices match 2011. However, to give you a range of the price sensitivity, that decline would be about 2% instead if Brent crude price were closer to $90 per barrel, or approximately 4% decline if Brent is closer to $130 a barrel. Overall, average growth rate from 2011 to 2016 is expected to be 1% to 2% per year, using the $111 average Brent price.
Base volumes from all of our currently producing fields are shown in the green and they do include future work programs. These volumes reflect a decline rate of 3% per year as unconventional and long-plateau volumes mitigate what has been an historically higher base decline rate. In addition, our volume outlook remains balanced with positive additions of both liquids and natural gas, as you’ll see on this next slide.
This chart provides the liquids and gas split of our production outlook, again at 2011 prices, and illustrates the strong contributions from both liquids and natural gas. Liquids production, which is shown in green, is anticipated to grow by 2% to 3% per year, on average, reflecting the benefit of the major project startups that have been described today. These projects will also add to our long-plateau volumes, which are expected to make up approximately 50% of our total volumes by 2015.
I hope we have provided you with an appreciation of the elements that we believe underpin ExxonMobil’s success in each of our principal business lines. As I said earlier, I am proud of our operating and financial performance and the competitive advantages which we believe we continue to capture. As all of you can appreciate, our primary focus is to maximize shareholder return over the long term, and we strive do so at a rate greater than our competitors as well as certainly the broader market.
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So let’s take a look at share performance. Financial results and stock market returns are, at least in my opinion, best viewed over longer periods of time, certainly for industries like ours which require very long-term capital investments and long cycle times for these investments to play out and produce results.
Although our short term performance matches the competition average over the past five years, ExxonMobil has generated greater shareholder value than the broader market and greater value than the average of our competitors over the last 10 and 20-year periods. Most dramatically, over the last decade the S&P 500 annualized return was 2.9%, versus ExxonMobil’s annualized return of 10.4%.
I’ll now recap why I believe ExxonMobil is well-positioned for the future. We are proud to play a leading role in providing the energy the world needs to support economic growth, technological advancement, and the well-being of communities around the globe.
Our Energy Outlook informs the foundation for our business plans because we know meeting future energy needs requires foresight and effective long-term planning. To support human progress, the world will need expanded supplies of traditional fuels, and our large, diverse resource base positions us well to continue developing conventional sources of energy.
But energy supplies will also continue to grow more diverse, and we are prepared with our leadership position in unconventional resource development. Asia Pacific and other non-OECD areas will drive demand growth. And our world-class LNG capabilities and projects like the Singapore chemical plant expansion are examples of how we are making strategic investments to support those regions.
Innovation and new technologies are needed to unlock energy sources, making them safe and affordable as we are continuing to fund our world-class research efforts and apply technology to unlock value across all aspects of our business.
And lastly, we know that unprecedented levels of investment are needed to meet the scale of the energy challenge, and ExxonMobil’s financial strength allows us to continue disciplined investments in strategic energy projects.
As demonstrated by our steady financial and operating performance, ExxonMobil is a leader in providing reliable, affordable energy in a safe, secure and environmentally responsible way. We have a balanced portfolio of high quality, material, and diverse resources and assets across the world.
Our focus on disciplined, selective investments underpins our ability to deliver superior returns. We’re also proud of our ongoing efforts to identify and develop new technology that enables us to unlock value and be more competitive and more efficient. With a focus on operational excellence, we develop and deploy systems to consistently apply the highest standards, leading to best-in-class operating performance.
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And finally, we capture substantial value across business lines through integration. We have built processes and systems that enable our organization to capture the highest value for each molecule. These strengths provide competitive advantage and allow us to continue maximizing long-term shareholder value.
That concludes the prepared remarks for this morning. At this time, I’m going to invite my colleagues on the management committee to join me in more comfortable chairs than you are in for the question and answer session.
QUESTION AND ANSWER
Rex Tillerson
I believe we have — are we on now? Are we all here? We’ve got microphones in the aisles so if you would wait until you receive a microphone, identify yourself.
Question 1
Can you guys hear me?
Rex Tillerson
Yes. You all got the mikes on back there? Okay.
Question 1 (clarification)
Is that better? So Rex, the growth and returns profiles for the big oil companies appears to be slowing versus the past 10 to 15 years and while Exxon leads the super majors on its distribution yield the balance seems to be skewed towards repurchases more so than dividends. And so my question is in light of these factors, how does the Company think about its distribution balances or the mix, in the future? And is there any difference in relation to years past?
Rex Tillerson
Well, obviously when you have a $37 billion capital program and we’re projecting, as you heard me say, $37 billion on average in the next five years, one of the things that we want to be certain is that we’ve got that financial capacity to fund those investment opportunities because clearly that — that is the most important thing to deliver, that value to our shareholders for many years to come.
We were and wanted to certainly, reacquire the shares that were issued for XTO on a — on a fairly deliberate path. And as I indicated, we think based on where we are now that will be done,
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concluded by the end of the first quarter. So as we’ve always said, we use that share repurchase program to help us manage the ups and downs of our cash flow that’s driven by and large by current day conditions, pricing.
We are mindful of our competitiveness in the dividend area. We know we are on the low end of yield, certainly within our sector. Relative to the broader market we’re better than the broader market.
So we’re going to evaluate that as we — as I said, wrap up the reacquisition of the XTO shares as we look at this very robust investment program we have in front of us and think about what price changes mean to future cash flow. Then we’ll be looking at that balance, which is not something we don’t do all the time.
As I indicated we have a long history, 28 years now growing dividends consecutively, and grown those dividends we think fairly sizable over the last five years, almost 6% last year. But we’re hearing our shareholders. I hear from them. We listen to them and I think they’re — it’s that question of within our sector are we where we should be on dividends? So I would just tell you we are mindful of it and we evaluate it. And I’m not going to give you any guidance one way or the other.
Question 1 (follow-up)
Thanks a lot.
Rex Tillerson
Yes, right over here.
Question 2
Hi, thanks. A couple questions. First on your CapEx and how that relates to return on capital employed, and then a quick one on Tanzania. On CapEx, you highlighted well I think on page eight, that you’re the only one of your peers to decline in return on capital employed relative to the preceding four years. Two influencing factors cited, of course capital not yet in service as I’d characterize it and then low natural gas prices.
So on those two points can you quantify the magnitude of capital not yet in service? How many billions of dollars do you have sitting there on the balance sheet that’s not being utilized today and the outlook for that?
And then what on the commodity price in natural gas specifically, what price deck would you need in order to avoid further dilution in the return on capital employed for the next five years?
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Rex Tillerson
Well, let me answer it this way and without being overly specific. On the incomplete construction number, obviously that’s a different number on any given day. Okay, it is, if you look at the big projects and I cited them, Kearl, Papua New Guinea, Kashagan certainly would fall in that — in that category. Some very — these are really some massive investment projects and our share of Gorgon Jansz in Northwest Australia. And you can look at when those are going to come on.
We’ve been — we’ve been carrying a fair amount of incomplete construction or recapitalization if you want to call it that, that’s not producing for some time. And you can go into the project by project data sheet and kind of add some numbers up. You won’t know —you may or may not be able to tell exactly which year those expenditures lined up, but we highlight it because it is, if you look historically, it is a larger percentage of the capital employed than it has been historically.
And that’s as you’d expect if you just look at what capital expenditures have done over the last five years. Some of which is opportunity-driven, some of which is just higher cost of execution today for everyone. So we highlight that.
The specific natural gas price, I’m not going to give any signals to anybody on that. It is because it’s very basin specific. There is not a price in which you’d say okay, now everything is performing where you want it to.
And it’s also certainly a punctual — we made the XTO acquisition of where we allocated the capital that came onto the books, on to existing resources at the time. So that number can be quite different depending on which basin we talk about, which — and how we’re developing and capitalizing those resources to bring them on production, so, there is not really a number. And that’s not the way we think about it. And so it’s not — I’m not trying to be overly evasive with you but, in all honestly we don’t manage — we don’t think about it and manage the business that way.
We look at the basin. We look at the cost. We look at what we can sell the gas and associated liquids for, and then we invest if it’s generating the kinds of double-digit returns that we want to have. And we know that with the XTO purchase we’ve got to continue capitalizing that resource base in the years to come to realize the full value.
And that’s why we indicated this was not about today. It’s not about generating a lot today. It is really about this future we see and the view that we have to be a significant participant in the supply of the energy that comes from this type of resource in years to come.
And it’s my view that, that big unconventional portfolio of the future will be the kind of cash cow return machine sitting underneath of all the future new investments. And it’s where our conventional portfolio has provided that in the past.
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Question 2 (follow-up)
I’m curious the year in which that becomes free cash flow positive. But then another quick one on Tanzania, can you confirm whether or not you have an oil presence in that first discovery, or is it still just gas and drilling deeper at this point?
Rex Tillerson
Well, I don’t — I don’t think we’re going to comment on Tanzania further than what the operator has announced at this point. As Mark indicated we’ve got an appraisal well planned or another well planned on another structure. So at this stage we really don’t think it would be appropriate to say anything further on that.
Question 3
Thanks, Rex. Good morning. In the volume guidance, Rex, I wonder if you can give us an idea if there has been any significant change in project mix? And specifically I guess you’ve been expecting this question. We’re all kind of familiar with what the XTO economics were.
At $2.25 gas and the bulk of your returns in the early part of the claim curve, I’m curious as to philosophically if you are continuing to drill dry gas wells in that portfolio why? Because it seems that it would be NPV negative, and if not how have your guidance — how does your guidance change in terms of is there lower gas volumes anticipated in your volume numbers?
Rex Tillerson
Let me make a very general comment, and then I’m going to ask Andy to speak to the mix of where XTO’s activities are and I’ll let Mark speak to whether the project — how the project mix is changing. First of all, we don’t comment on what our gas volumes are going — what we’re doing with our current production capacity, unlike what some others are doing.
Historically that’s not been viewed very favorably by people who worry about price collusion. So we’re going to be silent on that, and we’re going to be very — and we will be able to tell you where we are drilling, where our activity is. But we’re not going to talk about what we’re doing in terms of production.
So with that caveat, let me ask Andy to comment further on the unconventional activity, how we view the attractiveness of that, and then Mark can make any comments he wants to add on just the project mix.
Andy Swiger
I think what I’d add to that is first of all I talked a little bit about the liquids-rich portfolio that we have. We have been actively shifting more of the drilling into that liquids-rich portfolio, and as I noted, acquiring more of it at the same time. So you’re going to see full-time a continued shifting into that.
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Having said that, as Rex explained, there are some of the dry gas plays when we look at them on a play and a basin type basis where it still doesn’t make sense for us to continue investing. And that’s not only because of the economics, but also because we’re still in a delineation and definition phase, building for that long-term future.
It’s very important when you think about the future that we see for this business and the magnitude of the resource base we have, to understand it up front really well, and as I said, test technologies. Part of this program is doing things like the Fayetteville JITP test I talked about as well.
We’re also experimenting with different types of laterals, different types — numbers of frac stages, a variety of different things operational and technological to learn early on and delineate and apply what we think is a very, very important resource base for the future. So some dry gas drilling continuing for good reason, economic and otherwise, and a continuing shift over to more of our liquids portfolio.
Question 3 (follow-up)
(Inaudible question - microphone inaccessible)
Andy Swiger
I’m sorry, the what?
Question 3 (clarification)
(Inaudible question - microphone inaccessible)
Andy Swiger
Now, what I would say is if I thought about it instead of proportion of capital in terms of the total corporation on a mix of drilling we’re crossing the threshold of more than 50% going into liquids-rich now as I speak and moving on and upward.
Mark Albers
And on the project front there’s really been no change in the mix. All the projects are on track, on schedule. And I think that was reflected in the chart that Rex showed from the growth from ‘09 to ‘14. That’s the green performance wedge. There’s no fundamental shift there.
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Rex Tillerson
And I’d just build on what Andy was describing around the approach we take to the unconventional and why we’re drilling in, for instance, in some of the dry gas basins, because it really does go to why the XTO? Why the whole deal?
And it is that what started out as a roughly 6 billion to 7 billion barrel resource base we acquired, which as you saw now is up pushing 12 billion barrel resource base, a supply that as we view the world is going to be vital in the future and it’s going to have significant value. It’s what we’d do if we had gone out and discovered a 10 billion barrel oil field, what would we do? We would go out and we would apply all of our technical knowledge to understand that.
And we’d do that by drilling some appraisal wells. We’d do a lot of technology studies. We’d be trying to understand how are we going to get the maximum value out of this over the next 25 to 30 years?
And we’re approaching the unconventional resource space that way. Now, that is not the same model that all the other players out there would follow because they don’t have the size. They don’t have the technology resources, the research resources standing behind them. They don’t have the financial resilience to undertake a very deliberate evaluation program like this and a long-term improvement program around the development of those resources that we can take.
We can be patient. We don’t have to make a lot of money out of that right now. We’re going to make a lot of money out of it in the years to come, and we’re going to do that because we’re going to have an approach and we’re going to understand it better than anyone else does. It’s what we do with complex resources.
It’s the same thing we’d do if it was a single 8 billion barrel oil field sitting somewhere in Africa. We’d be taking the same approach. So philosophically that’s the way we think about this huge unconventional resource base that we now have captured. It is very much about how are we going to make that payoff and deliver a lot of value. Not this year, not last year, probably not next year but in many years to come.
So that as I said, when it rolls into that base, it is going to fund a lot of dividends and capital programs for the future. And that was — strategically, that’s what’s really behind that whole building of that resource capacity. Let me go to the back over here. Yes, right here. That’s fine.
Question 4
Rex, when you’re looking at the LNG business globally, what are you thinking about LNG exports from the U.S.? You obviously haven’t participated in that yet, but do you see this as being in the longer term large enough to move prices in the U.S.? And how do you see it as impacting on your existing Asian business, because that appears to be where most of the volumes are going to be focused?
43
And I kind of have two questions, please, on exploration. Firstly, on the Kara well. When do you think that the first well might be drilled on that acreage? And given the fact that it’s very close to the Yamal Peninsula, is there a chance there could be gas? And lastly, if I could, on Madagascar, you’ve had this on your charts for some time as a key well. When do you think you might be able to drill that given the political developments there?
Rex Tillerson
On your LNG export question, I assume you’re talking about liquefying lower 48 gas and exporting lower 48 gas not re-exporting from the LNG terminals?
Question 4 (clarification)
Yes, sure, and (inaudible - multiple speakers) as well.
Rex Tillerson
So let me let Andy speak to that. We’ve obviously been evaluating it. You say we haven’t entered it as others have. To my knowledge nobody’s doing it yet. There have been some permits issued but nobody’s actually doing it, so we’ll see if that happens or not. But let me let Andy comment, and then I’ll ask Mark to comment on your two questions around the Kara and Madagascar.
Andy Swiger
As I mentioned in my remarks, we are studying LNG export from North America overall, including the Gulf Coast. I think what you have to appreciate is what differentiates us from a number of people who have made a variety of announcements or jumped into permitting already is we have a pretty good understanding of the business all around the world, having been in it for over three decades.
And the risk management associated with the kinds of very large upfront capital investment decisions you make in pursuing something like that and building the liquefaction trains, developing the resource, setting up the commercial arrangements there.
And we believe it’s appropriate when we look at that and we look at all the other models and we think about how it will work on a global basis, to give it some time and attention before we decide what the best way to approach the business is, or if it’s a business worth approaching. And what I would say is we’re in the midst of that right now and don’t really have anything specific to say at the moment on that.
44
Mark Albers
On the Kara, as I’d indicated where the next step will be to run 2-D and then 3-D seismic to assess the prospects that we want to drill. Drilling time will be dependent on that evaluation, but notionally it’s in the 2014, 2015 timeframe.
In terms of the mix, we don’t expect it to be all gas or all oil. It’s going to be oil and gas and we’ve got a lot of work yet to do in terms of trying to understand it. And again, it’s an extension of the West Siberian oil and gas basin, so we would expect to see that in the Kara.
On Madagascar, we’re continuing to await resolutions with the government and the authorities to be able to move forward, and that’s hard to predict.
Question 5
Thank you. Rex, could you broadly characterize how you see mergers and acquisitions here? Whether you feel that you need to buy, either a large company or by theme, whether or not you feel that you could do it, for example, more West Africa or East Africa explorations. Or any other comments you could make around the relative attractiveness of — or where you may feel that you’re light going forward as a Company? Thanks.
Rex Tillerson
Well, I think we’ve — in many ways, we’ve filled in a lot of our portfolio that we felt was light with some things we’ve already done. As you would know, I would never rule out anything.
But I would also say that certainly in the oil price environment we’re in today, it makes it pretty rich. And in some parts of the world even gas assets can be fairly rich depending on where they’re located and what markets they’re proximate to.
What we are finding clearly, and certainly in North America in the current price environment we’re in, are a lot of really attractive asset opportunities and our preference is at this point, having done XTO to get the strategic elements in place, the material, large base and the organization that was necessary, we’re now finding a lot of very attractive things are walking through the door.
People know our door is open. We’re not having to really beat the bushes much, and we’re able to really much better today sift through those and understand we like this one because it’s synergistic with things we already are doing.
We do understand much better today the differential quality in these unconventional resources, and as we’ve been trying to help a lot of people and the public at large to understand these things are not homogenous. They’re not all created equal, and that’s true around the world.
45
So I think what we’re — today you’re more likely to see us continue to do more asset-type acquisitions just because the value around those is much better today. But again, you never rule out anything.
A company that finds itself in a circumstance that it would be a willing partner and where clearly there are synergistic and value uplift benefits, because whatever we do, just as we’ve always said, we’ve got to acquire it with a view that we’re going to add a lot of value to this. And that was — again, that was true with the Mobil merger, it was true with the purchase of XTO. We’re acquiring this because we see that we’re going to add a lot of value to this in the years to come.
So fundamentally that’s what has to always be there. So in terms of do we have holes in our resource base? I don’t see any big holes that cause us concern, and if you look at the map and the charts we’ve shown you, where we have been traditionally and where we are moving into new areas either by way of new contracts with national oil companies or farming into partners who are looking for partners sometimes because of the expertise we have to bring in certain areas.
So there’s nothing out there that I’d say gee, that’s a hole. We’ve got to patch that one. I think we by and large have taken care of that now in the last few years, and I think the focus our exploration program has, both the breadth of it and the mix of it is about right today.
Question 5 (follow-up)
Thanks.
Question 6
Thanks, Rex. I had a related U.S. shale oil, U.S. refining question. Over the decades, Exxon has been really one of the few companies that has really benefitted and taken advantage of being an integrated oil, both when the industry founded, but also in recent decades in contrast to many of your peer companies.
We’ve certainly been surprised with all the liquid shale growth how different the supply demand dynamics are here in North America, and frankly, globally. Do you believe being an integrated helps you pursue U.S. shale opportunities in a way different than a U.S. E&P, a pure play E&P? Is there an advantage to being an integrated either because of midstream or refining capabilities?
The related part of that is your U.S. refining system, I think, has been classically configured to benefit from the old flows. The heavy and sour crudes which I think most people think of as the discounted crudes.
Do you need to make changes there? Discounted crudes today, of course, often means light sweet from Rocky Mountain states. How is your U.S. refining configuration going to change? What plans are you doing there? Thank you.
46
Rex Tillerson
Okay. I’ll just give a very general answer then I’m going to let Mike really speak a little bit more to some of the specific areas you touch on. Yes, I’m convinced that the integration because we have the holdings Upstream, Downstream, Chemicals, and as we’ve tried to help people understand not just the fact that we own those businesses but the way in which we work them.
Our Upstream managers actually do sit down and talk with our refining managers, our Downstream managers, our petrochemical managers. And that’s not just, okay let’s once a year all sit down and hold hands and talk about how this is, how we can make this better.
The way people evaluate in the upstream, the resource, what is going to be the value of this thing? They want to know from the guys who are going to buy it, and the guys that buy it can give them a lot of insights. Even if we’re not going to be the buyer, they can give them an awful lot of insight on what’s this going to be worth.
And that helps us decide whether we ought to invest in that business or not, and it certainly helps when you get around to developing it. Are there some things we could do in the development plan that would give us greater value to the people that are going to buy this?
And so, there are clear, and we see it when these opportunities are brought forward by the organization to us, we see where those discussions have occurred. So in general there’s no doubt in my mind that the integrated model adds incremental value to just about everything we do.
Question 6 (clarification)
(Inaudible question - microphone inaccessible)
Rex Tillerson
Well, it may not be transparent to you. Sometimes it will appear in lower cost. Sometimes it will appear in higher margins because of how we’re able to manage logistics more efficiently.
There are any number of ways when you look at the full value chain and it’s not about, okay, we’re going to get it all right here. It’s about we’re going to get a little piece every little step of the way. We’re going to get a little piece that other people are not getting. Mike?
Mike Dolan (Senior Vice President)
Yes, I think in terms of the refineries, we have a very large system, of course, here in North America. You could think about the IOL refineries plus the ExxonMobil ones in the lower 48. We have a lot of diversity among those refineries. We do have some that are really well-configured for heavy crude.
47
Think of a Baton Rouge, a Baytown, but we have some other ones some Mid-Continent refineries. Joliet’s a good one for some of the heavy Canadian. But we have Sarnia in Canada, Billings where we run kind of a mixture of crudes, Beaumont as well. So we have a lot of crude flexibility.
In terms of modifications that we’ll make, we’re always looking to apply smart technology to help us have more flexibility on the feedstock side. So that’s what we invest in. We’ve looked a lot at how to utilize the assets we have with some technology tweaks and tucks without — we don’t want to get into a scrap and build program with a lot of capital in the business. The refining part of this doesn’t support those type of programs.
But we do have a really good technology group that can look at all the assets that we have and figure out the best way to optimize them, perhaps with debottlenecking and small investments and those things.
So I think between the spread of the assets we have, and there is some variety there, as well as the technical capability. We’ll adjust as we always have as these spreads kind of come and go.
Question 6 (clarification)
(Inaudible question - microphone inaccessible)
Mike Dolan (Senior Vice President)
Well I really don’t want to get into some of those specifics. There’s always practical limits to everything though, so —
Question 7
Thank you, Rex. I have actually three questions. One is very short. One is more on the industry and see if you can help us. One is more detailed on the project.
The short one is that, how many wells you going to drill in Germany — no, actually in Poland, yes, this year. And that at what point that you will say, okay, I know whether I have a good resource base I can work on.
Rex Tillerson
For Poland?
Question 7 (clarification)
Yes.
48
Rex Tillerson
Mark?
Mark Albers
It’s a fairly large position. We have drilled two wells as we’ve talked about, but we’re in the process now of conducting seismic so it’s premature to comment about future wells until we have the seismic analyzed and assessed. But it’s early days in Poland.
Question 7 (clarification)
Okay.
Rex Tillerson
You’ll be able to count — I think you’ll be able to count them on one hand for the foreseeable future because it’s very much an exploration program.
Question 7 (follow-up)
The second question is that Exxon probably have a more complete database than anyone in the private sector about global geologies. Wondering that, I mean there’s a big debate about how big is the shale oil potential whether it’s going to change the well outlook in the globalized supply? Want to see whether Exxon will be able to share some insight that outside North America, do you really see potential?
Rex Tillerson
Well the — if I can characterize it as the resource base, the in-place resource base is enormous, and it exists in many geographies around the world. Some of which, of course, we’re investigating like you just asked about in Poland.
There is extensive shale resource base in Europe. There’s extensive shale resource base in the Middle East, in Russia and in China. The real issue is not the fact that the resource base exists, but whether it has the characteristics that will allow you to apply the technologies that are known today, horizontal drilling, hydraulic fracturing, all the basic technologies that have resulted in commercialization of the shale resources in North America.
Whether those shales have the same characteristics that the technologies are going to be successful. And we know a whole lot more today. I can tell you we know a whole lot more today about what those characteristics are that are required than we knew three years ago.
49
And that’s because of the extensive core data that we got out of the XTO acquisition. They had thousands of feet of core that we didn’t have, and our researchers have gone to work on that. So our ability to go in and look at some of the basic characteristics, we can pretty well rule some things in and out.
What we know is there is a lot of shales in Europe that on today’s technology are probably not going to work. Will there be alternative technologies developed in the future that might make them work? We’re working on some of those technologies.
Some of it has to do with the way we hydraulically fracture and stimulate those shales to be successful in the Barnett or the Marcellus or the Ardmore don’t work in these shales because they have different characteristics. It doesn’t mean we can’t find some other stimulation technique that might work, but what we’re doing today doesn’t work.
And I would say the same — I think you’re going to find the same is going to be true for a portion of the resources in China. China’s getting a lot of play around unconventionals. They have a huge in-place, shale resource potential.
And there’s no doubt there will be some of those shales that probably will have the characteristics where current day technologies are going to be successful. We already know there are some portions of those shales, though, that have these other more challenging characteristics for which we’re going to have to develop some other way to cause the gas to be released and flow from those types of shales.
So what I guess the broad answer, Paul, is yes the resource base is enormous. The part of the resource base that is productive with current technology is very large. There’s a big piece of it that’s not productive under current technology, but it’s just like 10 years ago we didn’t think these shales were going to be commercial and now they are.
And our view has always been it’s always that you don’t know what you don’t know. And somewhere out there, my guess is we’re going to figure out how to make those shales that today we say are noncommercial, we’re going to figure out a technology to release that. It may be 20 years from now. It may be 30 years from now. So in terms of is it a big game changer? It is a big game changer. There’s no question about it.
Question 7 (follow-up)
A final question is the project-related to Kearl. When we’re looking at your total investment, if you get to 345,000 barrels per day you’re going to invest about $28 billion to $29 billion, roughly equal to about $83,000 per daily barrel production capacity.
Most of your competitors in the oil sands area will have a much lower development cost per daily barrel capacity, maybe talking about in the $30,000 to $40,000. We understand it’s not totally apple-to-apple, that you do some investment in the infrastructure they don’t, but how big is the benefit as a result of your higher investment that lead to a lower cash cost on a going forward? Can you quantify for us that to understand that how’s the tradeoff has been? Thank you.
50
Rex Tillerson
I’m going to let Mark comment on Kearl.
Mark Albers
Yes, first of all I would, I think as we look at the total Kearl project, we still think it’s in the $6 per barrel sort of range. I would challenge the notion that those facilities that are developed with an upgrader are going to be lower unit cost on a total basis. They will be significantly higher.
And I think, again, that’s why we’ve gone with this high temperature paraffinic froth treatment technology that enables us to treat the bitumen and get it in a dry form without solids and combine it with diluent and send it straight into the refining system. And on an operating cost you’re also going to have the benefit of not having all of that large upgrading kit to operate in the field. So we still see significant advantages.
Question 7 (clarification)
(Inaudible - microphone inaccessible) we’ll be talking about in the $30,000 to $40,000 per daily barrel production capacity. So that’s why that you surprise people with because of your new technology, you’re not using an upgrader. Most people thought that your development costs should be lower. So just want to see how big is your — because you’re paying the upfront costs that allow you to have a lower cash operating cost going forward? If you can help us to quantify how big is that benefit?
Mark Albers
Yes, well I think we’re comparing apples and oranges a little bit. When you look at a SAGD project and the capital per kbd kind of calculation which you’re referring to, that’s taken at the early stages. And then as it declines over the next 20 or 30 years, it’s obviously a lot different and much higher cost per barrel.
Kearl, as you’ve seen, is a very flat plateau, so yes, the initial few years on a capital per kbd ratio doesn’t look the same as a more peaky profile, whether it’s SAGD or the Gulf of Mexico. But over the long term we’re saving enormous amounts of capital per barrel — enormous.
Rex Tillerson
I don’t know, with your SAGD evaluation whether you are, as Mark said, incorporating what’s the dollar invested per average capacity over the life and also how much recapitalization do you have to do in SAGD because you have to keep putting capital back in? That’s just the nature of it.
51
And we operate the largest SAGD project out there so we’re pretty familiar with it. We’ve got time for one last question so let me go right here to this side.
Question 8
Your portfolio of shale in North America is quite gassy. Some concerns have been raised about whether oily rocks or the technology isn’t there to really exploit some of the oily rocks in North America. Is that an influence on your portfolio or is it just that the price of oil-rich assets is too expensive?
And then a separate question, you’ve got a very large position in Canada. Obviously there’s been disruption in terms of getting some of the Canadian crudes to market that we’re well aware of. What are you doing to solve the logistical issues of getting your Canadian oil to market?
Rex Tillerson
Let me let Andy respond to the oil-rich or liquids-rich shales and would just remind you, and if you go back to those charts and look at what our acreage holdings are, and some of these plays, I think, meet that characteristics. We have over 400,000 acres in the Bakken, over 800,000 acres in the Permian, 170,000 in the Woodford. I think our mix is pretty good, but I’ll let Andy comment further.
Andy Swiger
I would agree with that. I’d say go back and look at the charts and look at what we’re talking about doing in places like the Woodford Ardmore. Look at what we’re doing up in the Cardium in Canada right now which is an expanding play for us there. We have the technology.
We’re not in any way projecting a portfolio that’s dry gas heavy in some fashion. We’ve got a lot of liquid we’re working on. We have the technology. It’s very similar technology, slightly different applications with every different basin and so forth.
So there’s nothing holding us back, and as I mentioned before, we are shifting the rigs to more and more liquids-rich and we are looking for more liquids-rich opportunities. You’re correct in your assessment that the higher liquids-rich they are the pricier they would be to enter right now. But we’ve got a good position already that we’re still just beginning to delineate and define.
Rex Tillerson
On the Kearl evacuation question which I assume is triggered by the Keystone XL controversy, let me let Mike respond to that. I guess it’s one of those integration things that’s helpful because we do have refining, logistics, downstream expertise. They’re the ones that are helping the Upstream figure out how to get this out of there.
52
Mike Dolan
Yes, on Kearl and especially relative to the Keystone, Kearl starts up later this year so we already have our logistics plan in place. It’s not dependent on the XL pipeline phase. So we have all that worked out. Some of it goes to our own refineries. We have pipeline capacity to get into some of the markets, so we’re in pretty good shape at this point.
I guess our collective feeling is at a point in time the XL will get approved, and it will get built. It’s just right now it’s in a bit of limbo. But it makes good sense. The technical challenges will be overcome, the politics will catch up and the pipeline will get built.
Rex Tillerson
Well, we’ve got to cut it off at this point. They’re going to cut us off our telephone conference call. Otherwise we’ll have to buy another phone card. But I did want to thank all of you for coming and for your interest in ExxonMobil and for your questions. They’re all very good questions, and wish all of you the best in 2012. Thanks.
53
 2012 Analyst Meeting
March 8, 2012
New York Stock Exchange
Exhibit 99.2 |
 Cautionary Statement
2 |
 3
Agenda
9 AM
Welcome
David
Rosenthal,
Vice
President,
Investor
Relations
Business Overview
Financial & Operating Results
Rex
Tillerson,
Chairman
and
CEO
Competitive Advantages
BREAK
Mark
Albers,
Senior
Vice
President
Andy
Swiger,
Senior
Vice
President
Outlook
Summary
Q&A
12 PM
Meeting Concludes
Rex
Tillerson,
Chairman
and
CEO
Unlocking Greater Value in the
Upstream |
 4
Chairman and CEO
Rex Tillerson
Business Overview |
 5
Business Environment
Global environment offers a broad mix of challenges and opportunities
Near-term slowdown in global recovery with rising economic risks
Developing economies show signs of slowing but still outpace OECD economies
Significant regulatory initiatives continue while climate policies remain
uncertain Long-term outlook for energy and petrochemical demand remains
robust |
 6
Energy Demand to 2040
Global energy demand likely to grow approximately 30% by 2040
Energy Demand
Quadrillion BTUs
Oil
Gas
Coal
Other*
Annual Growth
Rate to 2040
1.6%
-0.2%
1.7%
0.7%
Pace of demand growth moderated
by efficiency gains across the world
Mix gradually shifts with oil and
natural gas remaining prominent
Strong growth in natural gas driven
by power generation needs
Source: ExxonMobil 2012 Outlook for Energy
* Other includes nuclear, hydro, geothermal, biomass, wind, solar, and
biofuels. 2040
2010
0
100
200
300 |
 7
Developing Economies Lead Growth
Energy Demand: OECD Countries*
Quadrillion BTUs
Non-OECD Countries
Oil
Gas
Other
Coal
Asia Pacific demand growth accounts for nearly 60% of global increase
Source: ExxonMobil 2012 Outlook for Energy
* OECD: Organization for Economic Co-operation and Development
0
100
200
300
400
500
2000
2020
2040
0
100
200
300
400
500
2000
2020
2040 |
 8
Liquids and Gas Supplies Expand and Diversify
Technology continues to expand economic supplies
Natural Gas
GCFD
Conventional
Unconventional
Liquids
MOEBD
Conventional Crude & Condensate
Deepwater
Natural Gas Liquids
Biofuels
Unconventional
Source: ExxonMobil 2012 Outlook for Energy
0
20
40
60
80
100
120
2000
2020
2040
0
100
200
300
400
500
600
700
2000
2020
2040 |
 9
Global Downstream Demand
Transportation energy demand increases nearly 45% percent by 2040
Developing countries driving growth,
especially Asia Pacific
OECD demand is flat
New capacity, alternative fuels, and
efficiency gains required
Transportation Energy Demand
MOEBD
OECD Countries
Non-OECD Countries
Source: ExxonMobil 2012 Outlook for Energy
0
25
50
75
2000
2020
2040 |
 10
Transportation Product Mix
Heavy duty transportation leads demand growth
Source: ExxonMobil 2012 Outlook for Energy
* Excludes other petroleum products (e.g., heating oil, fuel oil, LPG, kerosene, jet
fuel, naphtha). Petroleum Product Demand*
MOEBD
Gasoline
Diesel
0
25
50
2000
2020
2040
Significant shift in product mix
Diesel
growing
in
all
regions,
driven by economic activity
Gasoline flat to down, reflecting
efficiencies |
 11
Global Lubricants Demand
Demand expected to be nearly 20 percent higher in 2020 versus 2000
Demand growth of 1 percent per
year, driven by Asia Pacific
Global synthetics demand growing
6 percent per year
OECD demand flat but significant
growth within synthetics sector
* ExxonMobil assessment of industry demand
Lubricants Demand*
MB per Year
300
200
100
0
’00
’20
’15
’10
’05
OECD Countries
Non-OECD Countries |
 12
Global Chemical Demand
Chemical demand growth driven by Asia Pacific
Demand growth above GDP as
standards of living improve
Two-thirds of growth in Asia Pacific
Growth driven by preferred material
attributes
Demand and Global GDP*
Year-on-Year Percent Change
Demand Growth
Global GDP
Sources: ExxonMobil estimates and third-party GDP consensus opinions
* Chemical demand shown is polyethylene, polypropylene, and paraxylene. Bold
lines are trend lines. |
 13
The Energy Challenge
Meeting the world’s growing energy needs safely and responsibly
Requires broad-based economic solutions
Demands a commitment to innovation and technology
Calls for unprecedented levels of investment and diversity of supply
Requires sound, stable government policies
Demands effective risk management and operational excellence
|
 14
Risk Management
Risk management is fundamental to our business
Well-developed and clearly-defined
policies and procedures
Management accountability
High standards of design
Employee and contractor training
Rigorously applied management
systems |
 15
Operations Integrity Management System
Disciplined framework for the management of risk
Common global expectations
Integrated into daily operations -
it’s how we operate
Provides framework to meet or
exceed regulations
Ongoing assessments and
incorporation of learnings |
 Chairman and CEO
Rex Tillerson
Financial and Operating Results
16 |
 17
2011 Financial and Operating Results
Strong results across all key measures and business lines
Relentless Focus on Operational Excellence
Strong Financial and Operating Results
Disciplined Investments Focused on Long-Term Value
Unmatched Shareholder Distributions |
 18
Safety
Safety performance remains strong in industry
Relentless Focus on Operational Excellence
Our vision: Nobody Gets Hurt
Focus
on
operational
excellence
and
risk management
XTO implementing proven safety
management systems
Committed to continuously improving
safety performance
* 2011 industry data not available.
** XTO included beginning 2011.
Lost Time Incident Rate
Incidents per 200K hours
U.S. petroleum industry
contractor benchmark*
U.S. petroleum
industry employee benchmark*
Employee
Contractor
0.0
0.1
0.2
0.3
0.4
'07
'08
'09
'10
'11** |
 19
Environmental Performance
Committed to reducing environmental impact
Relentless Focus on Operational Excellence
* XTO included beginning 2011.
Hydrocarbon Flaring from
Upstream Oil & Gas Production
Million Metric Tons
0
2
4
6
8
'07
'08
'09
'10
'11*
Strong environmental
management
Improving energy efficiency
Reducing flaring, emissions,
releases
Protect Tomorrow. Today. |
 20
Earnings
Earnings of $41B in 2011, an increase of 35 percent over 2010
Strong Financial and Operating Results
Strong performance across all
business lines
Leveraging integration advantages
Maximizing value of asset base
Upstream
Downstream
Chemical
Total Earnings
0
10
20
30
40
50
'07
'08
'09
'10
'11
$B
Earnings Excluding Special Items |
 21
Upstream portfolio continues to deliver strong earnings per barrel
Upstream Earnings per Barrel
Balanced portfolio well-positioned
throughout business cycle
Disciplined approach to cost
management
Relentless focus on maximizing value
of each asset
Strong Financial and Operating Results
0
5
10
15
20
25
'07
'08
'09
'10
'11
Earnings per Barrel
$ per OEB |
 22
Upstream Volumes Growth
Project ramp-ups and strong unconventional performance drive growth
Strong Financial and Operating Results
-12
-10
-8
-6
-4
-2
0
2
2011 Volume Growth
Percent
XOM
CVX
RDS
BP
1 percent growth from 2010
Supported by risk management
and operational excellence
Largest
non
-government-owned
producer
of
oil and gas
at
4.5
MOEBD |
 Reserves Replacement
Strong Financial and Operating Results
Replaced 116 percent of 2011
production
Additions exceeded production for
the 18
th
consecutive year
Proved reserves increased to 24.9
BOEB
Proved Reserves Replacement*
Percent
* Reserves replacement based on SEC pricing bases and excluding
asset sales, except as noted in the Cautionary Statement.
0
50
100
150
200
250
'07
'08
'09
'10
'11
Consistently replaced more reserves than produced
23 |
 Return on Capital Employed
Return on Average Capital Employed*
Percent
2011
’07 –
’11, average
* Competitor data estimated on a consistent basis with ExxonMobil
and based on public information.
Strong Financial and Operating Results
0
5
10
15
20
25
30
XOM
CVX
BP
RDS
ROCE leadership supported by consistent business model
ROCE of 24 percent in 2011
Investments position long-term
performance
Disciplined investment through the
business cycle
Strength of integrated portfolio,
project management, and
technology application
24 |
 Cumulative
Proceeds
Associated
with
Asset
Sales;
2007
–
2011
$B
Capital Management
Strong Financial and Operating Results
Ongoing portfolio management
fundamental to business model
Targeted divestments across all
business lines
Retained assets which hold longer-
term shareholder value
Active asset divestments enhance shareholder value
0
10
20
30
'07
'08
'09
'10
'11
25 |
 2011 Cash Flow
Strong Financial and Operating Results
Strong cash flow, up nearly 30
percent from 2010
Year-end cash balance over $13B
Funded all attractive investment
opportunities
Continued to pay growing dividend
* Represents cash flow from operations and asset sales of $66.5 billion, including
$11.1 billion from asset sales. ** PP&E Adds / Investment &
Advances: Property, Plant, and Equipment ($31.0 billion) and Investments & Advances ($2.4 billion)
2011 Cash Flow
$B
YE’10
Cash
Cash
Flow*
PP&E
Adds/
Investment
&
Advances**
Share-
holder
Distri-
butions
Financing /
Other
YE’11
Cash
Share Purchases
Dividends
8
66
33
29
1
13
26
Superior cash generation provides investment and distribution flexibility
0
20
40
60
80 |
 Free Cash Flow Generation
Cash generation unmatched among peers
Total free cash flow generation of
$146B since beginning of 2007
Higher than competitors combined
Strong cash generation provides
capacity for shareholder distributions
* Competitor data estimated on a consistent basis with ExxonMobil and
based on public information.
Total
Free
Cash
Flow
(’07
–
’11)*
$B
Strong Financial and Operating Results
0
25
50
75
100
125
150
XOM
CVX
RDS
BP
27 |
 Capex
Disciplined Investments Focused on Long-Term Value
Capex by Business Line
$B
Invested $143B during the past five
years
Executed strategic acquisitions
Progressing major projects
Maintained capital efficiency and
discipline
Maintained focus on selective investments to deliver superior returns
0
10
20
30
40
'07
'08
'09
'10
'11
Upstream
Downstream
Chemical / Other
28 |
 Distribution Yield
Unmatched Shareholder Distributions
Total distribution yield of 34 percent
since beginning of 2007
Average distribution yield of 7.3
percent versus competitor average
of 5.1 percent
* Yield based on 2006 year-end market capitalization.
** RDS, BP, and CVX.
Total
Distribution
Yield
(’07
–
’11)*
Dividends
&
Share
Repurchases
Percent
0
5
10
15
20
25
30
35
ExxonMobil
Competitor Average**
29
Industry-leading shareholder distributions |
 Dividends
* S&P and CPI indexed to 1983 Exxon dividend.
** CPI based on historical yearly average from Bureau of Labor Statistics.
Dividend Growth since 1983*
$ per share
XOM
S&P 500
CPI**
Unmatched Shareholder Distributions
’83
’11
’01
’91
0.00
0.50
1.00
1.50
2.00
2.50
Reliable and growing dividends; $9 billion distributed in 2011
30
Over $40B distributed to
shareholders over past five years
Dividend has grown every year since
1983
Annualized growth rate
of
5.7 percent
Almost two times inflation |
 Share Reductions
Share purchases efficiently return cash to shareholders
$20B in shares purchases in 2011
Over 30 percent reduction in shares
outstanding since Exxon and Mobil
merger
Expect number of shares issued for
XTO to be repurchased by end of
1Q12
Shares Outstanding
Millions of Shares
* XTO acquisition occurred 2Q10.
Unmatched Shareholder Distributions
31
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
'00
'02
'04
'06
'08
2Q10*
'11 |
 Increasing Ownership
* Competitor data estimated on a consistent basis with ExxonMobil and based on
public information. ** Reserves
based
on
SEC
pricing
bases,
including
oil
sands
and
equity
companies.
2011
competitor
data
not
yet
available.
Production Growth per Share since 2007*
Indexed; 2007 = 100
Indexed Growth
Reserves Growth per Share since 2007* **
Indexed; 2007 = 100
XOM
BP
CVX
RDS
Indexed Growth
Unmatched Shareholder Distributions
32
Enhanced per share interest in ExxonMobil reserves and production
|
 33
2011 Financial and Operating Results
Strong results across all key measures and business lines
Relentless Focus on Operational Excellence
Strong Financial and Operating Results
Disciplined Investments Focused on Long-Term Value
Unmatched Shareholder Distributions |
 34
Competitive Advantages
Chairman and CEO
Rex Tillerson |
 35
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 36
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 37
2011 Resource Base
Balanced Portfolio
Upstream
Diverse resource base of over 87 billion oil-equivalent barrels
0
30
60
90
Africa
Australia/Oceania
Asia
Americas
Europe
Geography
0
30
60
90
Liquids
Gas
Liquids / Gas
0
30
60
90
Resource Base (BOEB)
Type
Unconventional
Oil and Gas
Arctic
Conventional
Heavy Oil /
Oil Sands
Deepwater
Acid / Sour
LNG |
 Resource Base Growth
Consistently adding quality resources at attractive finding costs
* Excludes XTO acquisition and the proved portion of discovered undeveloped
additions. ** Sources: Chevron Analyst Presentation (3/11), BP Strategy
Presentation (3/10), Shell Strategy Update (3/11) Annual Resource
Additions* BOEB
Discovered Undeveloped
By-the-Bit
Production
Upstream
$/OEB
Finding Cost (as reported)**
’02 -
’09
’04 -
’08
’08 -
’10
Balanced Portfolio
38 |
 Global Liquids Position
Upstream
Robust liquids portfolio of quality operations and advantaged projects
12.2 BOEB proved liquid reserves
Strong growth potential
Significant long-plateau volumes
LNG/Unconv
Heavy Oil /
Oil Sands
Conventional
Acid / Sour
Deepwater
Arctic
Liquids Resource Base
BOEB
2011 Liquids Production
Normal
Depletion
Long-
Plateau
Percent
Balanced Portfolio
39 |
 Global Gas Position
Upstream
Gas portfolio diverse in resource type, markets, and contract structures
76 TCF proved gas reserves
Large, diverse resource base
Leading unconventional position with
significant growth potential
LNG
Shale Gas
Conventional
Deep-
water
Acid / Sour
Tight Gas
Arctic
CBM/Other
Gas Resource Base
BOEB
Markets
BCFD
Europe
Asia
Americas
Africa
Middle East
Balanced Portfolio
40 |
 41
Production and Contract Mix
Upstream
Significant portion of production linked to oil pricing
0
1
2
3
4
5
Gas
Oil
Production Mix
MOEBD
Gas
Oil
2011
2015 Estimated
0
1
2
3
4
5
Oil
Oil
Indexed
Gas
Indexed
Oil
Oil
Indexed
Gas
Indexed
Contract Mix
MOEBD
2011
2015 Estimated
Balanced Portfolio |
 42
New Opportunity Growth
Upstream
Balanced Portfolio
Growing global portfolio of high-quality resource opportunities
Horn River
Alberta Tight Oil
Athabasca
Beaufort
Summit Creek
Gulf of Mexico
Guyana
Permian Basin
Rockies
Woodford
Utica
Colombia
Marcellus
Kara Sea
Vietnam
Indonesia
Russian Black
Sea
Norway
West
Greenland
Romania
Tanzania
Nigeria
PNG
Australia
Angola
Faroe Islands
Madagascar
Ireland
Argentina
China
Germany
Poland
Abu Dhabi
Iraq
New Play Tests
Unconventional
Conventional Discov’d/Undev.
Established Conventional Basin
Play Type |
 43
Scale Advantage
Largest global refiner with the highest level of integration
Average Refinery Size*
KBD
Downstream
Refineries 60 percent larger
than industry average
Leveraging scale to improve
profitability
* ExxonMobil average global refinery capacity compared to industry equity share
capacity; year-end 2011. Equity share capacity calculated on a
consistent basis using public information. Source: Oil & Gas Journal.
Balanced Portfolio
100
120
140
160
180
200
220
ExxonMobil
Industry Average
Cost efficiencies
Circuit optimization
Reliability
Feed flexibility |
 44
Lubricants Leadership Position
Largest basestock manufacturer and leading marketer of synthetics
Downstream
Global synthetics demand growing 6
percent per year
Industry leadership in basestocks and
synthetic lubricants
Well-positioned to capture growth
Market Position
Percent share
ExxonMobil
Competitor Average*
* ExxonMobil estimate of key competitor market share based on Kline industry
data and public information. Competitors include BP, RDS, and CVX.
Balanced Portfolio
0
5
10
15
20
Basestocks
Synthetic Lubes
Supported by advanced technology
and brand leadership |
 45
World-Class Brands
A leading marketer of high-quality products with trusted brands
Downstream
Global reach
Diverse sales channels
Global brands trusted for product
quality and supply reliability
Global Fuels Marketing Sales
Aviation
Marine
Retail
Industrial and
Wholesale
Percent, sales
Balanced Portfolio |
 Balanced Portfolio Maximizes Value
Facilities strategically located,
supplying all major growth regions
Commodities provide scale and
upside earnings capture
Specialties generate stable yet
growing earnings base
Proprietary technology underpins
portfolio
Earnings
$B
Commodities
Specialties
Chemical
Balanced Portfolio
0
1
2
3
4
5
'02
'03
'04
'05
'06
'07
'08
'09
'10
'11
46
Industry-leading Chemical performance driven by strong portfolio
|
 Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact
Technologies
Operational Excellence
Global Integration
47 |
 Project Inventory
Disciplined Investing
Upstream
Extensive portfolio supports selective investment decisions
Portfolio of 120+ projects
Developing 23 net BOEB across all
regions and resource types
Industry-leading project
management
High-impact technology
Investment selectivity
Project Distribution by Type
Percent, resource
Arctic
Heavy Oil /
Oil Sands
Conventional
Unconventional
Deepwater
LNG
Acid / Sour
9%
13%
15%
14%
36%
7%
6%
48 |
 Near-Term Project Start-Ups
Upstream
21 major project start-ups are planned between 2012 and 2014
Acid / Sour
Kashagan Phase 1
Oil Sands
Kearl
Nigeria
Satellites
LNG
Papua New Guinea
Arctic
Arkutun-Dagi
Deepwater Angola
Satellites
Deepwater GOM
Hadrian South / Lucius
Conventional
Kipper / Tuna
Disciplined Investing
49 |
 Major Project Production Outlook
Upstream
Significant new production supports long-term volumes
Over 1 MOEBD added by 2016
80 percent liquids volumes
Significant long-plateau volumes
Long-term growth supported by
diverse portfolio
* Outlook based on 2011 average prices (Brent crude $111/B).
Major Project Production Outlook*
MOEBD
Papua New Guinea
Gorgon Jansz
Hadrian South
Gas
Liquids
Usan
Kearl
Banyu Urip
AB17 Pazflor
West Qurna I
Upper Zakum 750
Kashagan Phase 1
Syncrude Aurora North
Kizomba Satellites Phase 1
Disciplined Investing
0.0
0.4
0.8
1.2
'11
'12
'13
'14
'15
'16
50 |
 Selective Investments
Increasing high-value diesel production for growing markets
Downstream
Global diesel demand expected to
rise by 85 percent through 2040
Recent investments contributed to
record ULSD production in 2011
Progressing additional investments to
supply more lower-sulfur fuels
Ultra-Low Sulfur Diesel Production
ExxonMobil, indexed
Disciplined Investing
100
150
200
250
300
'06
'07
'08
'09
'10
'11
51 |
 Portfolio Management
Downstream
Disciplined Investing
Global Asset Sales
(2003 -
2011)
Refineries
11
Pipeline Miles
5.9k
Terminals
145
Countries Exited
65
Retail Stations
16.8k
Ongoing portfolio management delivers value
52 |
 53
Effects from Portfolio Highgrading
Improved capital efficiency
Divestments reduced capital
employed more than 20 percent since
2003
Relatively low impact to earnings
Disciplined and ongoing approach to
capital management
Disciplined Investing
Downstream
Impact of Divestments / Restructuring
Percent, 2011 versus 2003; Downstream only
Capital
Employed
-23%
+5%
ROCE
Restructuring has driven a material decrease in our capital employed
|
 54
Singapore Expansion
Establishing world-class integrated platform to support Asia growth
Chemical
Two-thirds of chemical growth from
Asia Pacific
Once complete, largest refining-
chemical complex in our circuit
2.6 million tonnes of new capacity
98 percent mechanically complete
with units progressively starting up
Value capture accelerates as global
economy strengthens
Disciplined Investing |
 55
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 56
Technology Leadership
Developing fundamental science to meet the world’s energy challenges
Metallurgy solutions
for challenging
arctic conditions
Feed flexibility
advantage through
molecule
management
Corporate Strategic Research
Unique, world-class scientific
research capability
Fundamental research enables
identification of technology
opportunities
Foundation for technology
development in the business lines
Corporate
High-Impact Technologies |
 57
Research and Development
Progressing breakthrough research to develop high-reward, risk
reduction technologies across the Upstream business
Upstream
Imaging
Shale Gas / Tight Oil
Stimulation
Extended Reach
Drilling
Exploration
Development
Production
High-Impact Technologies |
 58
Extended Reach Drilling
Developing and applying integrated technologies to unlock greater value
Upstream
Horizontal Displacement
1980’s
1990’s
2000’s
Canada
California
Sakhalin
Drilled 23 of 27 longest-reach wells
Integrated suite of technologies from
modeling to wellbore planning
Increased capital efficiency and
access to additional reserves
High-Impact Technologies |
 59
Margin Improvement
Advantaged technologies enable our ability to improve margins
Downstream
Lower raw materials costs
Expanded feed flexibility
Increased refining utilization
Higher product realizations
“Discounted”
Crudes*
Percent, indexed
ExxonMobil
Industry Average
Source: ExxonMobil estimate based on public information.
* Includes “challenged”
crudes which are discounted in the market due to properties that make them
challenging to process. High-Impact Technologies
50
100
150
200
'04
'06
'08
'10
'11 |
 60
Feedstock Flexibility
Significant flexibility to process advantaged feedstocks
Facilities configured to run wide
range of feedstock
Access to range of feeds to
capitalize on lowest-cost options
Proprietary molecule management
technologies maximize value
Chemical
Worldwide Feedstock*
Percent
Advantaged
feeds
Benchmark
feeds
Source: IHS Chemical; full-year estimate as of September 2011.
* Ethylene feedstock; ExxonMobil data includes share of JV production.
High-Impact Technologies
0
25
50
75
100
ExxonMobil
Industry Average |
 61
Higher-Value Products
Advantaged technologies improve our products
Downstream / Chemical
Industry-leading
synthetic lubes
Higher-quality
fuel products
Premium chemical
products
High-Impact Technologies |
 62
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 63
People
Operational Excellence
Operational excellence begins with exceptional employees
Culture of excellence
Tailored, world-class training
Diverse, global work experiences
Host country workforce development
Corporate |
 64
Reliability and Cost Management
Best practices deliver strong reliability and life-cycle cost performance
Upstream
Strong reliability performance
Operated uptime >3 percent higher
than assets operated-by-others over
the last five years
-
Operational Excellence
Maintaining integrity of facilities
Disciplined global operating and
maintenance systems |
 65
Project Execution
Proven execution performance and delivery of complex projects
Rigorous project management
Superior cost and schedule delivery
Maximize efficiencies
Reappraisal to continuously improve
project performance
Upstream
* Actual versus funded cost variance (%); ’07 to ’11 project start-ups in ExxonMobil portfolio
Cost Performance*
2007 –
2011 Average
Percent
109%
103%
Operational Excellence
0
50
100
150
ExxonMobil Operated
Operated-by-Others |
 66
Cost Management
Disciplined and consistent approach to cost management
Continual effort to maximize the
value of each asset
Mature contracting strategies
Ongoing portfolio management
Upstream
* Upstream technical costs using 10-K/20-F information; beginning in 2009
equity companies and oil sands mining operations are included.
Total Costs per OEB*
$/OEB
CVX
RDS
BP
XOM
Operational Excellence
0
5
10
15
20
25
'06
'07
'08
'09
'10 |
 67
Angola and Sakhalin Developments
Delivering significant life-cycle value from frontier developments
Upstream
Enabling frontier developments with
differentiating technologies
Delivering operational excellence
Over 1.7 billion barrels produced
Over 95 percent uptime
Rapidly nationalizing the workforce
Maintaining strong government
relations
Operational Excellence |
 68
Improving Productivity
Focus on optimizing productivity delivers competitive advantage
Downstream
Ongoing consolidation activities
Integrated marketing company
announced in 2011
Streamlined product offering
Global organization, systems, and
processes driving lower operating
expenses
Supply Chain Operating Efficiencies
Indexed
Operational Excellence
50
60
70
80
90
100
'04
'06
'08
'10
'11 |
 69
Operating Efficiency
Sustaining high levels of operating efficiency
Downstream / Chemical
Refining and Chemical expanding
energy efficiency advantage
Globally shared best practices
Advanced technologies
Targeted investments
Refining Energy Intensity*
Indexed
ExxonMobil
Industry Average
* Data indexed to ExxonMobil (’04). Source:
Solomon Associates fuels refining benchmarking data; available for even
years. 2011 data estimated by ExxonMobil. Operational Excellence
90
95
100
105
110
'04
'06
'08
'10
'11 |
 70
Higher Operating Rates
Technology enables higher capacity utilization
Chemical
Reliability focus
Feedstock flexibility expands range of
economic operation
Fast-growing and high-value
derivatives
Global Steam Cracker Capacity Utilization
2007 –
2011 Average
Percent
ExxonMobil
Source: IHS Chemical
Operational Excellence
85
86
87
88
89
90
Industry Average |
 71
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 72
Maximizing Value through Integration
Global Integration
Corporate
Maximize value from Upstream
resource through to finished products
Leverage global functional
organization
Broadly deploy best practices
Economies of scale, shared support
services, purchasing
Maximize technology potential
Continuing to create value through the integrated business model
|
 73
Marketing New Crudes
Early integration across the supply chain enhances resource value
Upstream / Downstream
Upstream leveraging Downstream to
optimize equity crude value
Consistent integrated approach
Molecular assays
Crude valuation
Technical readiness
Refining capability and placement
Global Integration |
 74
Integrated Manufacturing
ExxonMobil has integration advantages that are difficult to replicate
Higher-value products
Integrated molecular optimization
Assets with unparalleled feed
flexibility
Common site management, utilities,
and infrastructure
Refining Integration with Chemicals/Lubes*
Percent
Downstream / Chemical
Source: Parpinelli Tecnon database
* Calculated on a consistent basis using public information; year-end
2011. Global Integration
20
40
60
80
ExxonMobil
Industry Average* |
 75
Industry-Leading Results
Downstream / Chemical
Proven business strategies enabled
by technology
Businesses optimized together to
maximize shareholder value
2008 –
2011 average annual
results:
Earnings of $8 billion
19 percent ROCE; nearly three
times the competitor average
* Competitor data estimated on a consistent basis with ExxonMobil and
based on public information. Competitors include BP, RDS, and CVX.
Downstream and Chemical Combined ROCE
Percent
ExxonMobil
Competitor Range
Global Integration
0
10
20
30
40
'08
'09
'10
'11
Downstream and Chemical businesses outperform competition
|
 76
Competitive Advantages
ExxonMobil possesses unique competitive advantages
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration |
 77
Senior Vice President
Mark Albers
Unlocking Greater Value in the Upstream
Senior Vice President
Andy Swiger |
 78
Upstream
Consistent execution of our strategies, underpinned by a relentless
focus on operational excellence, drives delivery of superior results
High-quality resources captured at
attractive costs
Effective partnerships
Distinguishing technologies
Proven project execution
Operational excellence |
 79
Meeting the Energy Challenge
Diverse and material portfolio across resource types of growing
importance in meeting global energy demand
0
30
60
90
2011 ExxonMobil Resource Base
Unconventional
Oil and Gas
Conventional
Heavy Oil / Oil Sands
Deepwater
Liquefied Natural Gas
Arctic
Acid / Sour
BOEB
* Source: ExxonMobil 2012 Outlook for Energy
World Oil and Gas Supply Growth*
MOEBD
2010 Production
2040 Production
Conventional
Deepwater
LNG
Unconventional
Oil and Gas
Heavy Oil /
Oil Sands
0.3%
2.8%
3.5%
5.3%
4.8%
Annual Growth
Rate to 2040
0
50
100
150 |
 80
Conventional
Delivering significant value from conventional resources
Note: Conventional includes arctic and acid/sour resource types
|
 Banyu Urip, Indonesia
Significant onshore oil development progressing on schedule
Conventional
450 MB oil resource
Early production of 20 KBD
165 KBD full field capacity
5 Full Field EPC contracts awarded
Anticipated start-up in 2014
81
Central
Processing
Facilities
Floating Storage &
Offloading Vessel |
 Sakhalin and Hebron
Applying proven arctic capabilities to progress additional developments
Arctic
Odoptu holds world record for extended
reach well
Arkutun-Dagi fabrication in progress and
on schedule for 2014 start-up
Initial engineering under way
82
Sakhalin
Hebron |
 Russia
Extending capabilities to significant new arctic acreage position
Arctic
Entered into Strategic Cooperation
Agreement with Rosneft
Kara Sea –
31 million acres
Extension of prolific West Siberia
hydrocarbon province
Progressing definitive agreements
Pursuing fiscal improvements
Commencing exploration activities
83 |
 Technology
Continuing to advance new technology solutions for arctic resources
Arctic
90 years of arctic technology
development
Progressing next-generation
technologies
Advanced arctic characterization
Ice management systems
Floating drilling
Gravity-based structures
Laboratory Ice Management Trials
Floating Arctic Drillship
84 |
 Deepwater
Building on established deepwater capability
Innovative design approaches
Early Production Systems
“Design One, Build Multiple”
Progressing
exploration
activities
West and East Africa
Black Sea
Gulf of Mexico
85
Cost-effective subsea satellite field
development
Exploration
Major Projects
Production Operations |
 Gulf of Mexico
Progressing development of discoveries in the Gulf of Mexico
Deepwater
Large, high-quality acreage position
Significant discoveries at Hadrian and
Lucius
Progressing developments
Lucius / Hadrian South funded
Hadrian North FEED under way
Julia Phase 1 FEED under way
Maturing prospect inventory
Oil Discovery
Gas Discovery
ExxonMobil Lease
Well
Lucius and Hadrian Discoveries
GOM Project Development Costs*
$/OEB (2012$)
Hadrian
South
Lucius
Hadrian
North
2 Miles
40
* Source: Wood Mackenzie
Discovery
ExxonMobil Participation
Industry
0
20
86 |
 Liquefied Natural Gas
ExxonMobil has leading global liquefied natural gas capability
ExxonMobil Participation
Industry
LNG Project
LNG Development Costs*
$/OEB (2012$)
* Source: Wood Mackenzie
0
10
20
87 |
 Papua New Guinea
Extending global LNG experience and project execution capabilities
Liquefied Natural Gas
High-quality 9 TCF resource
Two-train 6.6 MTA LNG plant
Progressing on schedule
Anticipate start-up in 2014
Active exploration program
88 |
 Unconventional Resources
Unconventional resource base
doubled since 2005
Accounts for over 40 percent of total
resource base
Gas growth balanced by strong
position in heavy oil / oil sands
Deep inventory of attractive
opportunities
Unconventional Resource Base
BOEB*
Unconventional
Oil and Gas
Heavy Oil /
Oil Sands
* Resource base at year end
89
0
10
20
30
40
Industry-leading global unconventional resource base
2005
2011 |
 North America
Unconventional Resources
Material position in unconventional resource plays across N. America
90 |
 Oil
Sands High-quality oil sands resource underpins long-term resource
value Kearl
Firebag
Ratio of material moved to bitumen in-place
Oil Sands Mining Resource Quality
10
11
12
13
6
8
10
12
Significant acreage position
Among the highest quality
Growth
area, material, long-plateau
production
91 |
 Kearl
High-quality resource and enabling technologies deliver long-term value
Oil Sands
Long-term plateau production profile
On schedule to commence operations
year-end 2012
Expansion Project fully funded with
start-up year-end 2015
Proprietary technology
Attractive returns
0
200
400
Debottleneck
Expansion
Debottleneck
Initial Development
Kearl Development
KOEBD
Kearl Development
KOEBD
92 |
 Technology
Emerging new technologies to further unlock oil sands value
Oil Sands
Paraffinic Froth Treatment
Eliminates need for on-site upgrader
Reduces GHG emissions and cost
Wet Tailings
Lowers tailings handling costs
Non-Aqueous Extraction
Significantly reduces water use
Avoids new wet tailings ponds
Higher bitumen recoveries
93 |
 North America Gas
Technology unlocking new supplies
Significant unconventional growth to
offset conventional decline
About 70 percent of North America
demand is met by unconventional
production by 2030
Source: ExxonMobil 2012 Outlook for Energy
Local Production to Meet Demand
Unconventional
Conventional
GCFD
4.4% avg annual
growth
Unconventional Oil and Gas
0
40
80
120
'00
'10
'20
'30
Significant gas production growth required to meet demand
94 |
 Unconventional Capability
XTO established the foundation of our global unconventional capability
Unconventional Oil and Gas
Key enabler to unlocking global
unconventional resource value
XTO managing 82 TCFE at year-end
Adding quality acquisitions at attractive
costs
15 TCFE at $0.23/KCFE
Leveraging XTO capability in global
pursuits
95
XTO Resource Base Evolution (U.S.)
TCFE |
 Liquids-Rich Plays
Unconventional Oil and Gas
Legacy tight oil positions in the Bakken
and Permian
Expanding Woodford Ardmore play
Over 170K net acres; 9 operated rigs
Develop ~600 MOEB at <$10/OEB
Growing portfolio of emerging plays
including Cardium in Canada
Gas
Liquids
96
Woodford Ardmore Development Scenario
KOEBD
0
40
80
2012
2017
2022
Well-positioned in liquids-rich unconventional plays
|
 Operational Excellence
Unconventional Oil and Gas
Mature play learnings being applied
to new plays
Continue to extract value even as
wells have become more complex to
drill
Systematic approach
Apply approach to global portfolio
Drilling Days Evolution
Percent Improvement
Time (years)
0
40
80
1
2
3
4
5
6
7
8
Operational efficiency and technology capture additional value
Barnett
Haynesville
Fayetteville
97 |
 Technology
Unconventional Oil and Gas
Enhanced perforating and stimulation
technologies
Reduce completion costs
Improve recovery
Enable water reuse
New technologies are further enhancing unconventional value
98 |
 Global Portfolio
Unconventional Resources
Growing global portfolio with early-mover, quality acreage pursuits
99
Indonesia
China
Canada
USA
Europe
Play Type
Colombia
Argentina
Shale Gas
Tight Gas
Coal Bed Methane
Tight / Shale
Oil
Heavy Oil / Oil Sands |
 Argentina
Unconventional Resources
100
ExxonMobil Current Drilling
Industry Vaca Muerta Exploration Well
Material position in the Vaca
Muerta play of the Neuquén Basin
Drilling commenced to evaluate
liquids and gas potential
Leveraging ExxonMobil
unconventional capabilities globally
Commencing exploration activities in a promising unconventional play
|
 101
Unlocking Greater Value
Superior value creation relies on high-quality resources, growth
markets, enabling technologies, and growing organizational capability
High-quality resources captured at
attractive costs
Effective partnerships
Distinguishing technologies
Proven project execution
Operational excellence
0
30
60
90
2011 ExxonMobil Resource Base
Unconventional
Oil and Gas
Conventional
Heavy Oil / Oil Sands
Deepwater
Liquefied Natural Gas
Arctic
Acid / Sour
BOEB |
 102
Chairman and CEO
Rex Tillerson
Outlook |
 103
Committed to investing through the business cycle
Investment Plan
Capex by Business Line
$B
Upstream
Downstream
Chemical / Other
Estimate ~$37B/yr
Disciplined, resilient investments
Progressing large inventory of
high-quality projects
Expect to invest approximately
$37 billion per year 2012 –
2016
0
10
20
30
40
50
'10
'11
'12
'13 -'16 |
 104
Upstream Production Outlook
Production in line with long-term growth estimates
2011 Production
MOEBD
* Excludes impact of future divestments and OPEC quota effects.
** 2011 Outlook as communicated in 2011 Analyst Meeting.
2009 to 2014 Growth Projections*
Percent Growth
4.0
4.3
4.6
2011
Analyst
Meeting
Outlook**
Price /
Entitlements
Performance
2011
Actual
2
3
4
5
2011
Analyst
Meeting
Outlook**
Price /
Entitlements
Performance
2012
Analyst
Meeting |
 105
Upstream Production Outlook
Production driven by strong performance, quality projects and resources
* Excludes impact of future divestments and OPEC quota effects.
Total Production Outlook*
MOEBD
Base Production
Project Volumes
0
2
4
6
'10
'11
'12
'13
'14
'15
'16
Projections based on 2011
average prices ($111/B Brent)
Volume outlook:
2011 to 2012: down 3 percent
2011 to 2016: up 1 to 2 percent/yr
Base decline rate of 3 percent
Unconventional and long-plateau
volumes mitigate
decline |
 Upstream Production Outlook
Balanced portfolio with strong contributions from liquids and gas
Projections based on 2011 average
prices ($111/B Brent)
Major projects and strong work
program drive growth
Liquids: 2 to 3 percent per year
Gas: 0.5 to 1 percent per year
Growing contribution of long-plateau
volumes
Total Production Outlook*
MOEBD
* Excludes impact of future divestments and OPEC quota effects.
Liquids
Gas
0
2
4
6
'10
'11
'12
'13
'14
'15
'16
106 |
 107
Chairman and CEO
Rex Tillerson
Summary |
 108
Long-term performance exceeds competitor average and S&P 500
Financial results and stock market
returns best viewed over long term
Reflects strong financial and
operating performance
Competitive advantages maximize
shareholder value
* RDS, BP, and CVX
Shareholder Returns
Value of $1,000 Invested (as of YE 2011)
$K
ExxonMobil
Competitor Average*
S&P 500
Share Performance
0
3
6
9
12
20 Years
10 Years
5 Years |
  Meeting the World’s Energy Challenges
Expanded supply
Expanded supply
of traditional fuels
of traditional fuels
•
Large, diverse resource base
•
Strong LNG portfolio
•
Strategic projects
•
World-class R&D programs
•
Technology to unlock value
•
Financial strength
•
Disciplined, resilient investments
Meeting Asia
Meeting Asia
Pacific demand
Pacific demand
growth
growth
Technology
Technology
advances
advances
Unprecedented
Unprecedented
levels of
levels of
investment
investment
Development of
Development of
new sources of
new sources of
energy
energy
•
Leadership in unconventional
resource development
Meeting the world’s growing
energy needs requires:
ExxonMobil has:
109 |
 ExxonMobil Strengths
Relentless focus on maximizing long-term shareholder value
Strong Financial and Operating Performance
Balanced Portfolio
Disciplined Investing
High-Impact Technologies
Operational Excellence
Global Integration
110 |
Exhibit 99.3
Frequently Used Terms
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures and other terms. These definitions are provided to facilitate understanding of the terms and their calculation. In the case of financial measures that we believe constitute “non-GAAP financial measures” under Securities and Exchange Commission Regulation G, we provide a reconciliation to the most comparable Generally Accepted Accounting Principles (GAAP) measure and other information required by that rule.
Note: Page numbers referenced in this document refer to ExxonMobil’s 2011 Financial and Operating Review.
Earnings Excluding Special Items — In addition to reporting U.S. GAAP defined net income, ExxonMobil also presents a measure of earnings that excludes earnings from special items quantified and described in our quarterly and annual earnings press releases. Earnings excluding special items is a non-GAAP financial measure, and is included to facilitate comparisons of base business performance across periods. A reconciliation to net income attributable to ExxonMobil is shown on page 85. We also refer to earnings excluding special items as normalized earnings. Earnings per share amounts use the same average common shares outstanding as used for the calculation of earnings per common share and earnings per common share – assuming dilution.
Total Shareholder Return — Measures the change in value of an investment in stock over a specified period of time, assuming dividend reinvestment. We calculate shareholder return over a particular measurement period by: dividing (1) the sum of (a) the cumulative value of dividends received during the measurement period, assuming reinvestment, plus (b) the difference between the stock price at the end and at the beginning of the measurement period; by (2) the stock price at the beginning of the measurement period. For this purpose, we assume dividends are reinvested in stock at market prices at approximately the same time actual dividends are paid. Shareholder return is usually quoted on an annualized basis.
Capital and Exploration Expenditures (Capex) — Represents the combined total of additions at cost to property, plant and equipment and exploration expenses on a before-tax basis from the Summary Statement of Income. ExxonMobil’s Capex includes its share of similar costs for equity companies. Capex excludes depreciation on the cost of exploration support equipment and facilities recorded to property, plant and equipment when acquired. While ExxonMobil’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.
Entitlement Volume Effects — Production Sharing Contract (PSC) net interest reductions are contractual reductions in ExxonMobil’s share of production volumes covered by PSCs. These reductions typically occur when cumulative investment returns or production volumes achieve thresholds as specified in the PSCs. Once a net interest reduction has occurred, it typically will not be reversed by subsequent events, such as lower crude oil prices. Price and Spend Impacts on Volumes are fluctuations in ExxonMobil’s share of production volumes caused by changes in oil and gas prices or spending levels from one period to another. For example, at higher prices, fewer barrels are required for ExxonMobil to recover its costs. According to the terms of contractual arrangements or government royalty regimes, price or spending variability can increase or decrease royalty burdens and/or volumes attributable to ExxonMobil. These effects generally vary from period to period with field spending patterns or market prices for crude oil or natural gas.
Heavy Oil and Oil Sands — Heavy oil, for the purpose of this report, includes heavy oil, extra heavy oil, and bitumen, as defined by the World Petroleum Congress in 1987 based on American Petroleum Institute (API) gravity and viscosity at reservoir conditions. Heavy oil has an API gravity between 10 and 22.3 degrees. The API gravity of extra heavy oil and bitumen is less than 10 degrees. Extra heavy oil has a viscosity less than 10 thousand centipoise, whereas the viscosity of bitumen is greater than 10 thousand centipoise. The term “oil sands” is used to indicate heavy oil (generally bitumen) that is recovered in a mining operation.
Proved Reserves — Proved reserves in this publication for 2009 and later years are based on current SEC definitions, but for prior years, the referenced proved reserve volumes are determined on bases that differ from SEC definitions in effect at the time. Specifically, for years prior to 2009 included in our five-year average replacement ratio, reserves are determined using the SEC pricing basis but including oil sands and our pro-rata share of equity company reserves for all periods. Prior to 2009, oil sands and equity company reserves were not included in proved oil and gas reserves as defined by the SEC. In addition, prior to 2009, the SEC defined price as the market price on December 31; beginning in 2009, the SEC changed the definition to the average of the market prices on the first day of each calendar month during the year. For years prior to 2009 included in our 18 straight years of at least 100-percent replacement, reserves are determined using the price and cost assumptions we use in managing the business, not the historical prices used in SEC definitions. Reserves determined on ExxonMobil’s pricing basis also include oil sands and equity company reserves for all periods.
Resources, Resource Base, and Recoverable Resources — Along with similar terms used in this report, refers to the total remaining estimated quantities of oil and gas that are expected to be ultimately recoverable. ExxonMobil refers to new discoveries and acquisitions of discovered resources as resource additions. The resource base includes quantities of oil and gas that are not yet classified as proved reserves, but which ExxonMobil believes will likely be moved into the proved reserves category and produced in the future. The term “resource base” is not intended to correspond to SEC definitions such as “probable” or “possible” reserves.
Proved Reserves Replacement Ratio — The reserves replacement ratio is calculated for a specified period utilizing the applicable proved oil-equivalent reserves additions divided by oil-equivalent production. See “Proved Reserves” above.
| CASH FLOW FROM OPERATIONS AND ASSET SALES |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Net cash provided by operating activities |
55,345 | 48,413 | 28,438 | 59,725 | 52,002 | |||||||||||||||
| Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments |
11,133 | 3,261 | 1,545 | 5,985 | 4,204 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Cash flow from operations and asset sales |
66,478 | 51,674 | 29,983 | 65,710 | 56,206 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments from the Summary Statement of Cash Flows. This cash flow is the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
1
| PP&E ADDS/INVESTMENTS & ADVANCES |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Additions to property, plant and equipment |
30,975 | 26,871 | 22,491 | 19,318 | 15,387 | |||||||||||||||
| Additional investments and advances |
3,586 | 1,239 | 2,752 | 2,495 | 3,038 | |||||||||||||||
| Collection of advances |
(1,119 | ) | (1,133 | ) | (724 | ) | (574 | ) | (391 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| PP&E Adds/Investment & Advances |
33,442 | 26,977 | 24,519 | 21,239 | 18,034 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
PP&E Adds/Investments & Advances is the sum of the cash used for additions to property, plant and equipment and net change in investments and advances (additional investments and advances minus the collection of advances). PP&E Adds/Investments & Advances is a measure of cash invested mainly in capital projects, including ExxonMobil’s investment in non-consolidated companies.
| FREE CASH FLOW |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Net cash provided by operating activities |
55,345 | 48,413 | 28,438 | 59,725 | 52,002 | |||||||||||||||
| Additions to property, plant and equipment |
(30,975 | ) | (26,871 | ) | (22,491 | ) | (19,318 | ) | (15,387 | ) | ||||||||||
| Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments |
11,133 | 3,261 | 1,545 | 5,985 | 4,204 | |||||||||||||||
| Additional investments and advances |
(3,586 | ) | (1,239 | ) | (2,752 | ) | (2,495 | ) | (3,038 | ) | ||||||||||
| Collection of advances |
1,119 | 1,133 | 724 | 574 | 391 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Free cash flow |
33,036 | 24,697 | 5,464 | 44,471 | 38,172 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Free cash flow is cash flow from operations and asset sales less PP&E Adds/Investments & Advances. This measure is useful when evaluating cash available for financing activities, including shareholder distributions, after investment in the business.
| PROVED RESERVES REPLACEMENT COSTS |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| Costs incurred (millions of dollars) |
||||||||||||||||||||
| Property acquisition costs |
3,787 | 45,461 | 1,285 | 663 | 194 | |||||||||||||||
| Exploration costs |
2,503 | 3,055 | 3,111 | 2,272 | 1,762 | |||||||||||||||
| Development costs |
25,690 | 23,210 | 17,130 | 14,633 | 11,570 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total costs incurred |
31,980 | 71,726 | 21,526 | 17,568 | 13,526 | |||||||||||||||
| Proved oil-equivalent reserves additions (millions of barrels) |
||||||||||||||||||||
| Revisions |
281 | 505 | 383 | 690 | 1,405 | |||||||||||||||
| Improved recovery |
— | 5 | 15 | 7 | 36 | |||||||||||||||
| Extensions/discoveries |
1,613 | 516 | 1,091 | 1,423 | 248 | |||||||||||||||
| Purchases |
67 | 2,510 | 1 | — | 2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total oil-equivalent reserves additions |
1,961 | 3,536 | 1,490 | 2,120 | 1,691 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Proved reserves replacement costs (dollars per barrel) |
16.31 | 20.28 | 14.45 | 8.29 | 8.00 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Proved reserves replacement costs per oil-equivalent barrel is a performance measure ratio and includes costs incurred in property acquisition and exploration, plus costs incurred in development activities, divided by proved oil-equivalent reserves additions, excluding sales. Unless otherwise specified, ExxonMobil reports these costs based on proved reserves using SEC historical prices and costs. See “Proved Reserves” on previous page.
| EXPLORATION RESOURCE ADDITION COST |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| Exploration portion of Upstream Capex (millions of dollars) |
5,464 | 4,121 | 3,718 | 2,871 | 1,909 | |||||||||||||||
| Exploration resource additions (millions of oil-equivalent barrels) |
3,906 | 4,725 | 2,860 | 2,230 | 1,995 | |||||||||||||||
| Exploration resource addition cost per OEB (dollars) |
1.40 | 0.87 | 1.30 | 1.29 | 0.96 | |||||||||||||||
Exploration resource addition cost per oil-equivalent barrel is a performance measure that is calculated using the Exploration portion of Upstream capital and exploration expenditures (Capex) divided by exploration resource additions (in oil-equivalent barrels – OEB). ExxonMobil refers to new discoveries, and the non-proved portion of discovered resources that were acquired, as exploration resource additions. Exploration resource additions include quantities of oil and gas that are not yet classified as proved reserves, but which ExxonMobil believes will likely be moved into the proved reserves category and produced in the future. The impact of the XTO Energy Inc. merger transaction is excluded in 2010.
2
| OPERATING COSTS |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Reconciliation of Operating Costs |
||||||||||||||||||||
| From ExxonMobil’s Consolidated Statement of Income |
||||||||||||||||||||
| Total costs and other deductions |
413,172 | 330,262 | 275,809 | 393,962 | 333,073 | |||||||||||||||
| Less: |
||||||||||||||||||||
| Crude oil and product purchases |
266,534 | 197,959 | 152,806 | 249,454 | 199,498 | |||||||||||||||
| Interest expense |
247 | 259 | 548 | 673 | 400 | |||||||||||||||
| Sales-based taxes |
33,503 | 28,547 | 25,936 | 34,508 | 31,728 | |||||||||||||||
| Other taxes and duties |
39,973 | 36,118 | 34,819 | 41,719 | 40,953 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Subtotal |
72,915 | 67,379 | 61,700 | 67,608 | 60,494 | |||||||||||||||
| ExxonMobil’s share of equity-company expenses |
11,401 | 9,049 | 6,670 | 7,204 | 5,619 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total operating costs |
84,316 | 76,428 | 68,370 | 74,812 | 66,113 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Components of Operating Costs |
||||||||||||||||||||
| From ExxonMobil’s Consolidated Statement of Income |
||||||||||||||||||||
| Production and manufacturing expenses |
40,268 | 35,792 | 33,027 | 37,905 | 31,885 | |||||||||||||||
| Selling, general, and administrative expenses |
14,983 | 14,683 | 14,735 | 15,873 | 14,890 | |||||||||||||||
| Depreciation and depletion |
15,583 | 14,760 | 11,917 | 12,379 | 12,250 | |||||||||||||||
| Exploration expenses, including dry holes |
2,081 | 2,144 | 2,021 | 1,451 | 1,469 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Subtotal |
72,915 | 67,379 | 61,700 | 67,608 | 60,494 | |||||||||||||||
| ExxonMobil’s share of equity-company expenses |
11,401 | 9,049 | 6,670 | 7,204 | 5,619 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total operating costs |
84,316 | 76,428 | 68,370 | 74,812 | 66,113 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy, staffing, and maintenance costs. They exclude the cost of raw materials, taxes, and interest expense and are on a before-tax basis. While ExxonMobil’s management is responsible for all revenue and expense elements of net income, operating costs, as defined above, represent the expenses most directly under management’s control and therefore, are useful for investors and ExxonMobil management in evaluating management’s performance.
| CAPITAL EMPLOYED |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Business Uses: Asset and Liability Perspective |
||||||||||||||||||||
| Total assets |
331,052 | 302,510 | 233,323 | 228,052 | 242,082 | |||||||||||||||
| Less liabilities and noncontrolling interests share of assets and liabilities |
||||||||||||||||||||
| Total current liabilities excluding notes and loans payable |
(69,794 | ) | (59,846 | ) | (49,585 | ) | (46,700 | ) | (55,929 | ) | ||||||||||
| Total long-term liabilities excluding long-term debt |
(83,481 | ) | (74,971 | ) | (58,741 | ) | (54,404 | ) | (50,543 | ) | ||||||||||
| Noncontrolling interests share of assets and liabilities |
(7,314 | ) | (6,532 | ) | (5,642 | ) | (6,044 | ) | (5,332 | ) | ||||||||||
| Add ExxonMobil share of debt-financed equity-company net assets |
4,943 | 4,875 | 5,043 | 4,798 | 3,386 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total capital employed |
175,406 | 166,036 | 124,398 | 125,702 | 133,664 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total Corporate Sources: Debt and Equity Perspective |
||||||||||||||||||||
| Notes and loans payable |
7,711 | 2,787 | 2,476 | 2,400 | 2,383 | |||||||||||||||
| Long-term debt |
9,322 | 12,227 | 7,129 | 7,025 | 7,183 | |||||||||||||||
| ExxonMobil share of equity |
154,396 | 146,839 | 110,569 | 112,965 | 121,762 | |||||||||||||||
| Less noncontrolling interests share of total debt |
(966 | ) | (692 | ) | (819 | ) | (1,486 | ) | (1,050 | ) | ||||||||||
| Add ExxonMobil share of equity-company debt |
4,943 | 4,875 | 5,043 | 4,798 | 3,386 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total capital employed |
175,406 | 166,036 | 124,398 | 125,702 | 133,664 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
3
| RETURN ON AVERAGE CAPITAL EMPLOYED (ROCE) |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Net income attributable to ExxonMobil |
41,060 | 30,460 | 19,280 | 45,220 | 40,610 | |||||||||||||||
| Financing costs (after tax) |
||||||||||||||||||||
| Gross third-party debt |
(153 | ) | (803 | ) | (303 | ) | (343 | ) | (339 | ) | ||||||||||
| ExxonMobil share of equity companies |
(219 | ) | (333 | ) | (285 | ) | (325 | ) | (204 | ) | ||||||||||
| All other financing costs – net |
116 | 35 | (483 | ) | 1,485 | 268 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total financing costs |
(256 | ) | (1,101 | ) | (1,071 | ) | 817 | (275 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Earnings excluding financing costs |
41,316 | 31,561 | 20,351 | 44,403 | 40,885 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Average capital employed |
170,721 | 145,217 | 125,050 | 129,683 | 128,760 | |||||||||||||||
| Return on average capital employed – corporate total |
24.2 | % | 21.7 | % | 16.3 | % | 34.2 | % | 31.8 | % | ||||||||||
ROCE is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow based, are used to make investment decisions.
| DISTRIBUTIONS TO SHAREHOLDERS |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||
| (millions of dollars) | ||||||||||||||||||||
| Dividends paid to ExxonMobil shareholders |
9,020 | 8,498 | 8,023 | 8,058 | 7,621 | |||||||||||||||
| Cost of shares purchased to reduce shares outstanding |
20,000 | 11,200 | 18,000 | 32,000 | 28,000 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Distributions to ExxonMobil shareholders |
29,020 | 19,698 | 26,023 | 40,058 | 35,621 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Memo: Gross cost of shares purchased to offset shares issued under benefit plans and programs |
2,055 | 1,893 | 1,703 | 3,734 | 3,822 | |||||||||||||||
The Corporation distributes cash to shareholders in the form of both dividends and share purchases. Shares are purchased both to reduce shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. For purposes of calculating distributions to shareholders, the Corporation only includes the cost of those shares purchased to reduce shares outstanding.
4
|
FUNCTIONAL EARNINGS(1) |
| |||||||||||||||||||||||||||||||||||
|
2011 Quarters |
||||||||||||||||||||||||||||||||||||
| (millions of dollars) | First | Second | Third | Fourth | 2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||||||||||||||
| Earnings (U.S. GAAP) |
||||||||||||||||||||||||||||||||||||
| Upstream |
||||||||||||||||||||||||||||||||||||
| United States |
1,279 | 1,449 | 1,184 | 1,184 | 5,096 | 4,272 | 2,893 | 6,243 | 4,870 | |||||||||||||||||||||||||||
| Non-U.S. |
7,396 | 7,092 | 7,210 | 7,645 | 29,343 | 19,825 | 14,214 | 29,159 | 21,627 | |||||||||||||||||||||||||||
| Total |
8,675 | 8,541 | 8,394 | 8,829 | 34,439 | 24,097 | 17,107 | 35,402 | 26,497 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Downstream |
||||||||||||||||||||||||||||||||||||
| United States |
694 | 734 | 810 | 30 | 2,268 | 770 | (153 | ) | 1,649 | 4,120 | ||||||||||||||||||||||||||
| Non-U.S. |
405 | 622 | 769 | 395 | 2,191 | 2,797 | 1,934 | 6,502 | 5,453 | |||||||||||||||||||||||||||
| Total |
1,099 | 1,356 | 1,579 | 425 | 4,459 | 3,567 | 1,781 | 8,151 | 9,573 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Chemical |
||||||||||||||||||||||||||||||||||||
| United States |
669 | 625 | 538 | 383 | 2,215 | 2,422 | 769 | 724 | 1,181 | |||||||||||||||||||||||||||
| Non-U.S. |
847 | 696 | 465 | 160 | 2,168 | 2,491 | 1,540 | 2,233 | 3,382 | |||||||||||||||||||||||||||
| Total |
1,516 | 1,321 | 1,003 | 543 | 4,383 | 4,913 | 2,309 | 2,957 | 4,563 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Corporate and financing |
(640 | ) | (538 | ) | (646 | ) | (397 | ) | (2,221 | ) | (2,117 | ) | (1,917 | ) | (1,290 | ) | (23 | ) | ||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Net income attributable to ExxonMobil (U.S. GAAP) |
10,650 | 10,680 | 10,330 | 9,400 | 41,060 | 30,460 | 19,280 | 45,220 | 40,610 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Special Items |
||||||||||||||||||||||||||||||||||||
| Upstream |
||||||||||||||||||||||||||||||||||||
| Non-U.S. |
– | – | – | – | – | – | – | 1,620 | – | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Corporate and financing |
– | – | – | – | – | – | (140 | ) | (460 | ) | – | |||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Corporate total |
– | – | – | – | – | – | (140 | ) | 1,160 | – | ||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Earnings Excluding Special Items(2) |
||||||||||||||||||||||||||||||||||||
| Upstream |
||||||||||||||||||||||||||||||||||||
| United States |
1,279 | 1,449 | 1,184 | 1,184 | 5,096 | 4,272 | 2,893 | 6,243 | 4,870 | |||||||||||||||||||||||||||
| Non-U.S. |
7,396 | 7,092 | 7,210 | 7,645 | 29,343 | 19,825 | 14,214 | 27,539 | 21,627 | |||||||||||||||||||||||||||
| Total |
8,675 | 8,541 | 8,394 | 8,829 | 34,439 | 24,097 | 17,107 | 33,782 | 26,497 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Downstream |
||||||||||||||||||||||||||||||||||||
| United States |
694 | 734 | 810 | 30 | 2,268 | 770 | (153 | ) | 1,649 | 4,120 | ||||||||||||||||||||||||||
| Non-U.S. |
405 | 622 | 769 | 395 | 2,191 | 2,797 | 1,934 | 6,502 | 5,453 | |||||||||||||||||||||||||||
| Total |
1,099 | 1,356 | 1,579 | 425 | 4,459 | 3,567 | 1,781 | 8,151 | 9,573 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Chemical |
||||||||||||||||||||||||||||||||||||
| United States |
669 | 625 | 538 | 383 | 2,215 | 2,422 | 769 | 724 | 1,181 | |||||||||||||||||||||||||||
| Non-U.S. |
847 | 696 | 465 | 160 | 2,168 | 2,491 | 1,540 | 2,233 | 3,382 | |||||||||||||||||||||||||||
| Total |
1,516 | 1,321 | 1,003 | 543 | 4,383 | 4,913 | 2,309 | 2,957 | 4,563 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Corporate and financing |
(640 | ) | (538 | ) | (646 | ) | (397 | ) | (2,221 | ) | (2,117 | ) | (1,777 | ) | (830 | ) | (23 | ) | ||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| Corporate total |
10,650 | 10,680 | 10,330 | 9,400 | 41,060 | 30,460 | 19,420 | 44,060 | 40,610 | |||||||||||||||||||||||||||
|
|
|
|
||||||||||||||||||||||||||||||||||
| (1) | Total corporate earnings means net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income statement. Unless indicated, references to earnings, special items, Upstream, Downstream, Chemical, and Corporate and Financing segment earnings, and earnings per share are ExxonMobil’s share after excluding amounts attributable to noncontrolling interests. |
| (2) | See Frequently Used Terms on pages 93 through 95. |
5
| RETURN ON AVERAGE CAPITAL EMPLOYED(1) BY BUSINESS |
| |||||||||||||||||||||
|
(percent) |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||||
| Upstream |
||||||||||||||||||||||
| United States |
9.3 | 12.2 | 18.2 | 42.6 | 34.7 | |||||||||||||||||
| Non-U.S. |
39.2 | 29.0 | 24.8 | 56.7 | 43.7 | |||||||||||||||||
| Total |
26.5 | 23.3 | 23.4 | 53.6 | 41.7 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Downstream |
||||||||||||||||||||||
| United States |
42.5 | 12.5 | (2.1 | ) | 23.7 | 65.1 | ||||||||||||||||
| Non-U.S. |
12.1 | 15.6 | 10.9 | 34.8 | 28.7 | |||||||||||||||||
| Total |
19.1 | 14.8 | 7.1 | 31.8 | 37.8 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Chemical |
||||||||||||||||||||||
| United States |
46.2 | 53.0 | 17.6 | 16.0 | 24.9 | |||||||||||||||||
| Non-U.S. |
14.4 | 17.6 | 12.6 | 22.4 | 39.0 | |||||||||||||||||
| Total |
22.1 | 26.3 | 13.9 | 20.4 | 34.0 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Corporate and financing |
N.A. | N.A. | N.A. | N.A. | N.A. | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Corporate total |
24.2 | 21.7 | 16.3 | 34.2 | 31.8 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| (1) | Capital employed consists of ExxonMobil’s share of equity and consolidated debt, including ExxonMobil’s share of amounts applicable to equity companies. |
| See Frequently Used Terms on pages 93 through 95. |
| AVERAGE CAPITAL EMPLOYED(1) BY BUSINESS |
| |||||||||||||||||||||
|
(millions of dollars) |
2011 | 2010 | 2009 | 2008 | 2007 | |||||||||||||||||
| Upstream |
||||||||||||||||||||||
| United States |
54,994 | 34,969 | 15,865 | 14,651 | 14,026 | |||||||||||||||||
| Non-U.S. |
74,813 | 68,318 | 57,336 | 51,413 | 49,539 | |||||||||||||||||
| Total |
129,807 | 103,287 | 73,201 | 66,064 | 63,565 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Downstream |
||||||||||||||||||||||
| United States |
5,340 | 6,154 | 7,306 | 6,963 | 6,331 | |||||||||||||||||
| Non-U.S. |
18,048 | 17,976 | 17,793 | 18,664 | 18,983 | |||||||||||||||||
| Total |
23,388 | 24,130 | 25,099 | 25,627 | 25,314 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Chemical |
||||||||||||||||||||||
| United States |
4,791 | 4,566 | 4,370 | 4,535 | 4,748 | |||||||||||||||||
| Non-U.S. |
15,007 | 14,114 | 12,190 | 9,990 | 8,682 | |||||||||||||||||
| Total |
19,798 | 18,680 | 16,560 | 14,525 | 13,430 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Corporate and financing |
(2,272 | ) | (880 | ) | 10,190 | 23,467 | 26,451 | |||||||||||||||
|
|
|
|
||||||||||||||||||||
| Corporate total |
170,721 | 145,217 | 125,050 | 129,683 | 128,760 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| Average capital employed applicable to equity companies included above |
31,626 | 30,524 | 27,684 | 25,651 | 24,267 | |||||||||||||||||
|
|
|
|
||||||||||||||||||||
| (1) | Average capital employed is the average of beginning-of-year and end-of-year business segment capital employed, including ExxonMobil’s share of amounts applicable to equity companies. See Frequently Used Terms on pages 93 through 95. |
6