David S. Rosenthal
Good morning. For those of you that I 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 case of an evacuation, direct us to the nearest exit. So please wait for the instructions if this were to occur. I would also 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 statement 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?
Rex W. Tillerson
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 can 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 tampering 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 make 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. 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 the 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 1/3 of demand. Advances in technology will continue to be important to help expand liquids fuel supplies. As conventional crude oil production holds relatively flat, demand growth will be met by newer sources. As you can see on the chart on the left, large gains are expected from global deepwater sources, with production more than doubling through the year 2040. 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 liquid 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 3 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%. The 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. OECD 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 the 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 refinings capabilities and may well further alter the fuel mix of the future.
As shown in the chart, the transportation product mix is changing. We expect a continuing shift to 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 drivetrains, 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. Over the next 10 years, the global synthetic sector is forecast to grow at 6% per year, with 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. 2/3 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 life cycle 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 as advanced new energy sources, as we have recently seen with natural gas from shale and new supplies of oil from resources previously deemed noncommercial. An unprecedented $1.5 trillion per year of investment will be needed globally to develop technology and resources that expand and diversify the supply base. The 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 risk 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. 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 highest 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 upfront during the design stage to reduce or eliminate risk 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 the 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 or 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 nonfinancial 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 the leadership in safety performance and strong environmental management. We also delivered excellent financial and operating results with superior returns. We continued to invest with a discipline focusing on creating long-term value while maintaining a perspective that transcends the year-to-year economic conditions. 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's distracted from running the business. Our vision that Nobody Gets Hurt is a central 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 high 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 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 life cycle 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. In 2007, we have decreased hydrocarbon -- 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 0 hydrocarbon spills from both company-operated, as well as term-chartered vessels. In our current operations and as we develop projects for the future, we will continue working to protect tomorrow, today.
Let's now take a look at 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 5 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're 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 5 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 produced 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 employee 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 -- 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 1/3 higher. ROCE, while still strong, has been impacted by low natural gas prices in the United States. 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 facility startup 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 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 long-standing 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 5 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 proceed 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 5 years, our free cash flow before shareholder distributions was almost $146 billion. This is unmatched among our peers and higher than all of our competitors combined. 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 5 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 actually able to add acreage in 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 9 Upstream projects expected to come online during the years 2012 and 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 5 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 5 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 5 years, we distributed over $40 billion in dividends to shareholders. During this same period, we increased per-share dividends 45%. Since 1983, through expansions and contractions to 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 and 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. The share purchase program continues to be an effective way to distribute value to shareholders while at 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 repurchase 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 3 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 and 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 risk 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. Conventional oil and gas, unconventional resources and heavy oil are the largest components comprising 2/3 of our total. The balance includes acid and sour gas in all sources, such as Kashagan, Tengiz and LaBarge; significant liquified natural gas holdings in Qatar, Northwest Australia and Papua New Guinea, Arctic, including Prudhoe Bay and Sakhalin and deep water 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 cost, as you'll see on the next slide.
The chart on the left shows our annual resource additions over the last 5 years. 5 of these 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 cost 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 costs.
Let's now look at our liquids 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. 44% (sic) [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, pipe 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.
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 gas -- 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 1/4 of our gas volume is sold under contracts that have some type of linkage to oil prices. Including these gas volumes, about 2/3 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 in 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 lubes 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 levels 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 that on the next slide
As I mentioned earlier, we anticipate strong growth in the lubricants demand, with significant growth in the synthetic sector, which is growing at a rate of 6% per year. We are the world's largest lube-based stock manufacturer and the leading marketer of synthetic lubricants. As shown on the graph, we have 3x more base stock market share and more than twice the synthetics lubes market share than our competitor average. We're also well-positioned to capture growth. In the high-value finished lubricant sector, we've 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 that have captured significantly higher sales growth in 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 a leading marketer and supplier of transportation fuels to a diverse set of business segments and industries. Our reach is global, with fuels marketing in more than 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 3 business-to-business segments include industrial, wholesale, marine and aviation. And together, these segments make up over 50% of total fuels marketing sales. Our 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 when the 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 deliver an efficient and productive capital base. Let's start with the Upstream.
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 managed our entire portfolio from discovery to startup. Constant technology enhancements allow us to develop innovative solutions that continue to improve safety and deliver projects with attractive unit development costs and maximize the value of the investment over the entire life of the resource. The diversity and scale 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 and 2013. In 2012 and '13, we expect to start up 9 major projects, 7 of which are liquids projects, including 4 in West Africa, Kashagan Phase 1 in Kazakhstanand the Kearl oil sands project in Canada. In 2014, 12 projects are expected to come online, 7 of which are liquids projects, including Arkutun-Dagi in Russia, Navia [ph] 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 5 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 through a buildup in long-plateau volumes.
Let's now take a look 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 5 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 underway, including new facilities at 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 the South and Central America, as well as in Switzerland and Malaysia. And more recently, we announced plans to restructure our holdings in Japan. 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 interest in 11 refineries and have fewer non-strategic 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 now look 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 2/3 of global demand growth over the next 3 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 underway. 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.
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 this technology and integration and 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've 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 per year on research and technology developments and have over 10,000 active issued patents. 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 Ph.D. scientist 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 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 3 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 the 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 to 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 boreholes 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 uplifts across the full value chain from early modeling and wellbore planning, through patented and proprietary technologies that enable the safe drilling and completion of these record linked 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.
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 cost 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 the industry in our ability to run discounted challenged crudes, running 50% more in 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 3 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 2 factors help us to maximize low-cost ethane use in 2011. And third, we have molecule management tools that enable realtime re-optimization of process flows. And our close integration with refining provides ultimate 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.
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 advance catalyst and processes to efficiently upgrade a wide variety of crudes into a wide range of products. For example, we have several or 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 catalyst, 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 compromises 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.
Our focus on reliability and cost management is an integral part of ExxonMobil's operations, and it is an important component in maximizing the resource value. 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 5 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 held an interest. This is the equivalent of 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 life cycle. Strong reliability not only leads to safe operations, but helps to drives 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 cost for project 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 5 years, we have delivered operated projects on average within 3% of funded cost, 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 cost and schedule 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 a 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 high-grade 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 life cycle value. In Angola, we have produced over 1.4 billion oil equivalent barrels, with the first production of Kizomba C beginning 23 months after sanctioned, which was a record in 2008. The application of our "Design One, Build Multiple" approach has significantly reduced project cost 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 in 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. This 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 of 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.
Our strategies and execution have also enabled our Chemical assets to be more productive. In the chart, you can see a comparison of the 5-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 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 through capture advantages.
The effective and efficient implementation of our integrated business model allows ExxonMobil to capture significant value across our holdings from the Upstream, through 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 high 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 leveraged 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've 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 backstop processing capabilities.
A recent example of our success with an 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 organizations have the technical knowledge to optimize processing of this important new resource. These early integration across supply chain enhances our overall resource value, as we will solve many of the challenges prior to startup. Next, let's look at the integration of 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 realtime whether molecules should be made into fuel product, lubricant base stock 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 on a wide range of feedstocks, which help us reduce operating cost 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 3x higher than the competitive average. These results clearly demonstrate the unqualified benefits we achieved 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 creation of long-term shareholder value.
I'll now turn it back to David to review the remaining agenda.
David S. 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.
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 W. Albers
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, and 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 life cycle 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 of 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. Beginning on the far left, the conventional supply is, of course, very large in absolute terms. And it's 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 4 Saudi Arabias. Not surprisingly, the fastest growing segments includes the unconventional and the heavy oil resources.
If you look on the right, you can 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 to take you through several examples of that, beginning with conventional resources.
Our conventional resources delivers 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, 4D seismic and enhanced drilling capabilities are significantly extending the life of these fields, and increasing remaining reserves by 1/3. As shown by the blue dots, major development projects for conventional resources are underway around the globe. And I'll highlight a few of them now, and we will 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 underway to add further well capacity and production facility capacity and additionally, we've got a 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 underway on the artificial islands and extended reach drilling is expected to commence around midyear.
In Vietnam, we made a material gas discovery in the second half of last year. And we have additional drilling planned this summer. We also made 2 discoveries, one oil and one gas in Indonesia, near our Banyu Urip development.
As we look to the future, we signed a 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. And as you know, in 2011, we signed 6 production sharing contracts in the Kurdistan region of Iraq, with a total license area of 848,000 acres.
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. Oilfield 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 have now ordered all the major engineering, procurement and construction contracts and full field development is progressing on schedule with startup 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 at 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 page of Sakhalin-1, we've completed construction of the gravity base 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 underway 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 and 3 blocks as you see in the map. To put that into 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 physical improvements that are needed to move us into the next phase. Exploration activities will commence this year with 2D and 3D 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 now 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 realtime operational decisions. We're working to extend the drilling season beyond the available open water season.
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. These 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 underexplored, 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, Nigeria and Equatorial Guinea led to significantly reduced costs and accelerated field startups. Recently, we've also applied innovative technologies to develop satellite fields through subsea tiebacks with 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 and very high-quality reservoir sands. We and our partner, Statoil, are planning to drill a follow-up well to test the second prospect on the block.
In Romania, in the Black Sea, we are also recently successful with a new play test in the deepwater. Additional follow-up drilling is planned once we acquire and assess additional 3D seismic on the block. The Gulf of Mexico has also been a highlight. 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. More 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 to start up in 2014.
Hadrian North will be a 100,000 barrel per day capacity development with a new-build semisubmersible floating production system. We have appraisal drilling planned this summer, and FEED is underway. We have a 50% working interest in Hadrian North.
As shown on the lower left, the Lucius and Hadrian
Developments have among the lowest unit development costs of current Gulf of Mexico deepwater projects, supported by 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 tieback to the Jack St. Malo facility. Front-end engineering and design are underway, 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 planed in the next 12 months. Moving now to LNG.
We have established a leading global capability here building on over 3 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 help to expand the global market. Today, we're 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're developing a high-quality 9-trillion cubic foot gas resource. The project includes a 2 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 the pipe racks and the tank foundations at the LNG site. We also have a very active exploration program with 2 wells planned this year and additional seismic. And this activity is designed to support expansion studies for a third train.
With that, I'd like to introduce Andy, who will now speak to our unconventional resources.
Andrew P. Swiger
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 2 supplier areas we project to have the strongest global growth over the coming decades. Heavy oil in 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 in 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 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 2 dots in the lower left corner of the chart will need to mine approximately 1.5x 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 cost, Kearl will have advantage 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 the 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 comments operations by year-end 2012. Production rates are expected to be 110,000 barrels of bitumen per day. As the second step of the phased Kearl oil sands development, the Kearl expansion project has been fully funded and will bring 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 on-site upgrader, which avoids a multibillion 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 for the scale of the Kearl operation, which will result in reduced handling cost and accelerate land reclamation. We are 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 the potential to significantly reduce freshwater 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 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 or will account for more than 70% of demand in 2030 versus about 40% in 2010.
We are focusing on continuing to capture the upside potential of this North American demand growth and are in the early stages of accessing 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 global value from these resources is XTO Energy. As shown on the chart, XTO is 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 thousand 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 in 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 7 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're evaluating unconventional potential across roughly half of our 800,000-acre leasehold. Our liquids-rich Woodford Ardmore play continues to expand with 9 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 cost 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 8 wells drilled by year end with 3 online. Early results from this play are encouraging, with average first month per well production of about 275 barrels per day. 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 -- or one example of this knowledge transfer is shown on the chart, which compares the history of drilling efficiencies in our most mature shale play, the Barnett, with 2 early stage shale plays, the Fayettville and the Haynesville.
In the Barnett, more than 1,600 wells drilled over the past 8 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 life cycle. Here, drilling days per well have improved to 24% in the third year of drilling even as the average measured depth in the wells has increased to 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 in a play development model based on experience for 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-type gas wells. JITP allows us to fracture multiple intervals in a well in a very highly selected 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 to push set the 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 stimulation stages are completed, the well is put online and produced.
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 the 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 a drilling and testing operation. In Europe, we drilled wells in Germany and Poland. Testing of the Germany wells is pending regulatory approval. The 2 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 3D seismic data in Poland, and we 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 coalbed methane play. In China, we signed a joint study agreement to evaluate the Sichuan Basin gas -- shale gas potential. Technology development and application will be one of the key elements in maximizing the full value these resources. Now let's take a 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 partner to develop a plan to test and evaluate the play by leveraging our XTO and ExxonMobil experience. The first 2 wells spud in December, will test the liquids and gas potential of the play.
Let me conclude by summarizing how we had 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, developments 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.
Rex W. Tillerson
I think I needed to plug into a battery source earlier. Well, I want to thank Mark and Andy for their overview, that they provided you on a little deeper understanding of our Upstream business. I'm going to move 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 continued to dominate with the 2011 bar including the Phillips acquisition. Downstream and chemical projects spending reflects ongoing investments, as I indicated earlier, the strength and 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 barrel 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 was going to be.
As you can see, the higher price basis does reduce growth outlook, but that is partially 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've 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 the 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 for 2016 on that same basis that I've just described to you. Our continued focus on reliable operational performance and new high-quality projects expected to start up, 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 prices were closer to $90 a 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 projects start-ups 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 provided you an appreciation of the elements that we believe underpin ExxonMobil's success in each of our principal business lines. As I said earlier, I'm 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 to do so at a rate greater than our competitors as well as, certainly, the broader market.
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 5 years, ExxonMobil has generated greater shareholder value than the broader market and greater value than the average of our competitors over the last 10- to 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 suppliers 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 in 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. And we're 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 high standards leading to best-in-class operating performance. 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.
Rex W. Tillerson
I believe we have -- are we on now? Are we all here? We've got microphones in the aisle, so if you would wait 'til you receive a microphone, identify yourself. Doug?
Douglas Terreson - ISI Group Inc., Research Division
Doug Terreson, ISI. Could you guys hear me?
Rex W. Tillerson
Yes. You got mics on back there? Okay.
Douglas Terreson - ISI Group Inc., Research Division
Doug Terreson, ISI. Yes, 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 W. Tillerson
Well, Doug, 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 5 years, one of the things we want be certain is that we've got that financial capacity to fund those investment opportunities because clearly, 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 fairly deliberate path. And as I indicated, we think, based on where we are now, that will be done, concluded by the end of first quarter. So as we have 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, grown those dividends we think fairly sizable over the last 5 years, almost 6% last year. But we're hearing our shareholders. I hear from them. We listen to them. And I think there is that question 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 your any guidance one way or the other.
Yes, right over here.
Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
It's Robert Kessler, Tudor, Pickering, Holt. A couple of questions. First, on your CapEx and how that relates to return to capital employed and then a quick one on Tanzania. On CapEx, you highlighted, well, I think, on Page 8 that you were the only one of your peers to decline and return on capital employed relative to the preceding 4 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 2 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? Any outlook for that? And then what, on the commodity price and natural gas specifically, what price deck would you need in order to avoid further dilution in the return on capital employed for the next 5 years?
Rex W. 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've cited them, Kearl, Papua New Guinea, Kashagan certainly would fall in that category, some very -- these are really massive investment projects, and our share of Gorgon Jansz in Northwest Australia. And then you can look at when those are going to come on. 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 highlighted 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 5 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 is very basin-specific, there is not a price at which you'd say, "Okay, now everything is performing where you want it to." And it's also certainly a function when we made the XTO acquisition of where we allocated the capital that came onto the books, onto 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 be overly evasive with you, but in all honesty, 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 the 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.
Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
I'm curious to 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 W. Tillerson
Well, 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 any further -- anything further on that.
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Doug Leggate from Bank of America. In the volume guidance, Rex, I wonder if you could give us an idea if there's 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 decline curve, I'm curious as to philosophically, if you are continuing to drill dry gas wells in that portfolio, why? Because it would seem 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 W. Tillerson
Let me make a very general comment, then I'm going to ask Andy to speak to the mix of where the 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 be viewed very favorably by people who worry about price dilution. So we're going to be silent on that. But we're going to be -- 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.
Andrew P. Swiger
I think what I'd add to that is, first of all, I'll talk a little bit about the liquids-rich portfolio that we have. We have been actively shifting more at 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. Having said that, and 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 that magnitude of the resource base we have, to understand it upfront 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 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 a good reason, economic and otherwise, and a continuing shift over to more of our liquids portfolio.
I'm sorry, the what?
Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
Andrew P. Swiger
No, 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 upward.
Mark W. Albers
And then the projects, frankly, there has really been no change in the mix. All the projects are on track, on schedule. 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.
Rex W. 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 world, is going to be vital in the future, and it's going to have significant value. It's what we do if we had gone out and discovered a 10 billion barrel oilfield. 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 we're 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 oilfield 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 we're 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, back over here. Yes, right here. That's fine.
Iain Reid - Jefferies & Company, Inc., Research Division
It's Ian Reid from Jefferies. 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 this as being, in the longer term, large enough to move prices in the U.S.? And so how do you see it as impacting on your existing Asian business because that appears to be where most the volumes are going to be focused. And I kind of have 2 questions, please, on exploration. Firstly, on the Kara well. When do you think the first well might be drilled on the acreage? And given the fact it's fairly close to the Yamal Peninsula, is there a chance that could be gas? And lastly, if I could, on Madagascar, you've had this on your chart for some time as a key well. When do you think you might be able to drill that given the political developments there?
Rex W. Tillerson
On your LNG export question, I assume you're talking about liquefying lower 48 gas and exporting the lower 48 gas, not re-exporting LNG...
Iain Reid - Jefferies & Company, Inc., Research Division
Rex W. Tillerson
So let me at Andy speak to that. We've obviously been evaluating it. You say we haven't entered it as others have. To my knowledge, nobody is doing it yet. There've 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 2 questions around the Kara and Madagascar.
Andrew P. Swiger
As I mentioned in my remarks, we are studying LNG exports 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 3 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 won't -- don't really have anything specific to say at the moment on it.
Mark W. Albers
Yes. On the Kara, as I'd indicated, we're -- the next step will be to run 2D and then 3D 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 time frame. In terms of the mix, we don't expect it to be all gas or all oil. It's going be oil and gas. And, well, we got a lot of work yet to do in terms of trying to understand that. 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 resolution with the government on -- and the authorities to be able to move forward. And that's hard to predict.
Paul Sankey - Deutsche Bank AG, Research Division
Paul Sankey of Deutsche Bank. Rex, could you broadly characterize how you see mergers and acquisitions here? Whether you feel that you need 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 exploration, or any other comments you can make around the relative attractiveness of -- or way you may feel that you're light going forward as a company?
Rex W. Tillerson
Well, I think, we've -- in many ways, we 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 bush as 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 in the public at large to understand, these things are not homogeneous. They're not all created equal. And that's true around the world. 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 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 the mobile merger. It was true with the purchase of XTO. We're acquiring this because we see that we're going to have a lot of value in this in the years to come. So that, 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 just 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 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.
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
Rex, it's Arjun Murti with Goldman Sachs. I had a related U.S. shale oil and U.S. refining question. Over the decades, Exxon has been really one of the few companies that has really benefited 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 certainly have been surprised with all the liquids 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 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 suite from Rocky Mountain states. How is your U.S. refining configuration going to change what plans you're doing there?
Rex W. 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 touched on. Yes, I'm convinced that our -- 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 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 be the buyer, they can give an awful lot of insight of 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 -- there are clear, and we see it when these opportunities are brought forward by the organization to us, we see where that -- those discussions have occurred. So, in general, there is no doubt in my mind that the integrated model adds incremental value to just about everything we do and...
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
Rex W. Tillerson
Well, it may not be transparent to you. Sometimes it will appear in lower cost. Sometimes it will appear in lower -- in higher margins because of how we're able to manage the 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?
Michael J. Dolan
Yes. I think in terms of the refineries, we have a very large system, of course, here in North America. If you 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 well-configured for heavy crews. Think of a Baton Rouge or 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 talks without -- we don't want to get into scrap-and-build program with a lot of capital of 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, and 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 and...
Arjun N. Murti - Goldman Sachs Group Inc., Research Division
Is there [indiscernible]
Michael J. Dolan
Well, I really don't want to get into some of those specifics. There's always practical limits to everything, though, so...
Rex W. Tillerson
Paul Y. Cheng - Barclays Capital, Research Division
Paul Cheng, Barclays. I have actually 3 questions. One is very short. One is more of the industry, and see if you can help us. One is more detailed on the project. The short one is that how many wells are going to drill in Germany -- no, actually in Poland? Yes, I think -- yes. And that at one point that you would say, "Okay, I know whether I have a good resource base I can work on?"
Rex W. Tillerson
Paul Y. Cheng - Barclays Capital, Research Division
Rex W. Tillerson
Mark W. Albers
It's a fairly large position. We have drilled 2 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.
Rex W. Tillerson
We'll be able to count -- I think now, you'd be able to count them on one hand for the foreseeable future because it's very much an exploration program.
Paul Y. Cheng - Barclays Capital, Research Division
And the second question is that Exxon probably have a more complete database than anyone in the private sector about the 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 world outlook in the global oil supply. I want to see whether Exxon will be able to share some of the insight that outside North America, do you really see potential?
Rex W. 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 is 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 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 3 years ago. 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's 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 hydraulic, refracture and simulate 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 it -- what we're doing today doesn't work. And then I would say the same -- I think you're going to find the same is going to be true for a portion of that 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 -- 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.
Paul Y. Cheng - Barclays Capital, Research Division
A final question is the project-related to Kearl. When we're looking at your total investment, you get to 345,000 barrels per day. You're going to invest $28 billion, $29 billion. Roughly, you go to about $83,000 per daily barrel production capacity. Most of your competitor in the oil sand area will have a much lower development cost per daily barrel capacity, and maybe talking about in the 30,000 to 40,000. We understand it's not totally apples-to-apples, that you do some investments 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 the trade-off has been?
Rex W. Tillerson
I'll let Mark comment on Kearl.
Mark W. Albers
Yes. First of all, Paul, 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 upgrade are going to be lower unit cost on a -- on a total basis, they will be significantly higher. And I think, again, that's why we've gone to 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. So in 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.
Paul Y. Cheng - Barclays Capital, Research Division
[indiscernible] you say 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 are not using an upgrader. Most people thought that your development costs should to be lower. So just want to see how big is your -- because you are paying the upfront cost, so that allowed you to have a lower cash operating cost going forward, if you can help us to quantify, how big is that benefit?
Mark W. Albers
Yes. Well, I think we're comparing apples-and-oranges a little bit. When you look at the SAGD project and do a 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 don't -- 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 W. Tillerson
Yes, I don't know, Paul, within -- 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. 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.
Edward Westlake - Crédit Suisse AG, Research Division
Ed Westlake of Credit Suisse. 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 the -- 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 political issues of getting your Canadian oil to market?
Rex W. Tillerson
Well, let me let Andy respond to the oil rich, or liquid rich shales. And would just remind you, and if you go back to those charts and look at what our acreage holdings are in some of these plays, I think meet that characteristic. We have over 400,000 acres in the Baken; 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.
Andrew P. Swiger
Well, I'd agree with that. So if you go back and look at the charts and look at what we're talking about doing in places like the Woodward, 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 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 W. Tillerson
On the Kearl evacuation question, which I assume is triggered by the Keystone XL controversy, let me let Mike respond to that. 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.
Michael J. 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 to 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 will get built. It's just, right now, it's in a bit of limbo. But it makes good sense, the technical challenges, we overcome, the politics will catch up, and the pipeline will get built. So...
Rex W. 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 do 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 I wish all of you the best 2012. Thanks.
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