David Rosenthal - Vice President, IR and Secretary
Rex Tillerson - Chairman and CEO
Mike Dolan - Senior Vice President
Mark Albers - Senior Vice President
Andy Swiger - Principal Financial Officer and Senior Vice President
Arjun Murti - Goldman Sachs
Doug Terreson - ISI
Robert Kessler - Tudor, Pickering
Paul Sankey - Deutsche Bank
Jason Gammel - Macquarie
Ed Westlake - Credit Suisse
Evan Calio - Morgan Stanley
John Herrlin - Societe Generale
Dave Rewcastle - Source Capital Group
Iain Reid - Jefferies
Paul Cheng - Barclays
Kurt Wulff - McDep
Faisel Khan - Citigroup
ExxonMobil Corporation (XOM) 2013 Analyst Meeting Conference Transcript March 6, 2013 9:00 AM ET
Good morning. For those of you that I’ve not met, my name is David Rosenthal. I’m the Vice President of Investor Relations and Secretary of ExxonMobil. I like to welcome everybody today to our 2013 Analyst Meeting.
But before we begin, 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. And in the event of an emergency, the 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 instructions if this were to occur. I would also ask everybody to please ensure that your cell phones and all mobile devices are turned off at this time.
Next, I would like to draw your attention to the cautionary statement that you will find in the front of your presentation material. This statement contains information regarding today's presentation and discussion. If you’ve not previously read the statement, I would encourage you to do so at this time.
You may also refer to our website, exxonmobil.com, for additional information on factors affecting future results, as well as supplemental information defining key terms that we will use throughout the meeting today.
The first four sections of our presentation today will be covered by Rex Tillerson. We will start with the corporate overview, which include key messages for today's meeting and our 2012 financial and operating results. This will be followed by a look at the business environment we operate in and key factors influencing the oil, gas and chemical businesses. We will then discuss key elements of ExxonMobil’s corporate strategy across all of our business lines followed by an overview of how we are executing this strategy in our upstream business.
Mike Dolan will follow with the discussion of how we are implementing our strategies in the downstream and chemical businesses. Following Mike’s discussion we will take a short break after which Rex will conclude our prepared remarks with a summary including an outlook on our forward investment plan. We will then conduct a 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?
Well, thank you, David, and good morning all, because I say every year it’s a -- it’s nice to be visiting New York City. Hopefully, we will be able to exit the city as scheduled given that we’ve got some weather coming in, but that’s not all bad either, cold weather is okay.
This the 11th year now that we’ve held our Investor Meeting here at New York Stock Exchange and I want to express my appreciation to folks here at the Exchange for their support they give us when we host this event. They do a remarkable job accommodating us every year and we really do thank them for that.
I do want to welcome all of you who have joined us for this our 2013 Analyst Meeting. Obviously, those of you who are here in the room with us but also anyone the folks out there listening by telephone or may have logged in to the webcast we welcome you as well.
Today it is my pleasure to review several topics, including elements of our business that enable ExxonMobil to deliver superior long-term shareholder results.
I’m going to start with a quick review of the key messages that I hope to leave you with today. First, our relentless commitment to risk management and operational excellence is central to how we run our business. Second, we delivered another year of strong financial and operating results in 2012.
Third, the major projects we have been executing now over the past few years will profitably grow volumes in the years to come. Fourth, our balanced portfolio of high-quality business lines and rich portfolio of investment opportunities position us to profitably grow under a wide range possible market conditions. And finally, our long held strategies when executed well continue to deliver superior returns to our shareholders over the long-term.
And looking back on 2012, overall I’m well pleased when assessed across a variety of financial, as well as non-financial measures. First and most importantly, we continued our relentless focus on operational excellence including safety performance and environmental management.
We delivered earnings of almost $45 billion. Our return on average capital employed in excess of 25% and a cash flow from operations and asset sales of almost $64 billion. These results reflect the strength of our proven business model and enable us to fund our investment program in a discipline way, and deliver unmatched shareholder distributions. In 2012, we invested nearly $40 billion in capital expenditures, which included about $3 billion of acquisitions and total shareholder distributions were over $30 billion.
For the 19th consecutive year, we added more oil and natural gas reserves then we produced and our proved reserve replacement rate exceeded 100%. All of the above results reflect the hard work, diligence and dedication of almost 77,000 men and women who work on ExxonMobil’s behalf the world over.
We know from experience that the pathway to maximize positive outcomes for our customers, stakeholders and investors is to effectively manage the risk inherent in our business. So now I’ll review our approach to risk management.
Risk management is a business imperative and ExxonMobil has developed a robust risk management approach based upon decades of experience and continuous improvement. This approach is supported by well-developed and clearly defined policies and procedures to ensure that we have a structured globally consistent system with the high standard in place.
Management commitment and accountability in all aspects of the business are essential to achieving expected results. We rigorously incorporate high standards of design and operating practices into all new operations to mitigate or eliminate significant risk.
Employee and contractor training is an essential element to managing risk to achieve appropriate competencies at all levels within the organization and most importantly to embed the right behaviors. All of this is done within the context of experience based rigorously applied management systems.
In place now for more than 20 years and broadly recognized as a model of success, ExxonMobil's Operations Integrity Management Systems or OIMS provide a disciplined framework for managing safety, security, health and environmental risk.
ExxonMobil’s OIMS has been broadly adopted by others as a template for their own systems. OIMS establishes a common expectation around the world for managing risk. It is employed that ExxonMobil facilities and operations across the globe and it is incorporated into the daily operations. It is not merely a set of written processes and procedures. It is our culture. It is how we operate the business everyday, 24x7 365.
Let’s now take a look at our approach to personnel safety. As you 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.
We also know the safety performance is a leading indicator of business performance. Our vision that nobody gets hurt is fundamental to operational excellence, while never satisfied, our safety performance remain strong and improving with a relentless focus on effective risk management.
In 2012, performance improved notably from 2011, which is some of you will recall represented a basis change from 2010 as a result of our first year of inclusion of the XTO operating organization.
As a result of the integration of our safety and OIMS practices, XTO's performance has measurably improved, both employee and contractor workforces experienced reductions in incident severity with our employee lost time incident rate nearing our best ever performance levels.
We remain dedicated to the high standards of safety and health, and are committed to continuing this improvement trend. To do so requires relentless focus and commitment at all levels within the company, an organization cannot be complacent or content with its past safety performance, and we will not be satisfied until we conclude -- 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 only environment is one of society's greatest challenges.
At ExxonMobil rigorous environmental management programs to deliver ongoing improvement in our global environmental performance throughout the lifecycle of our operations are in place.
The results of this disciplined focus are significant, particularly in area of energy efficiency. For example, in 2002, 10 years ago, we made a commitment along with others in our industry to achieve a 10% improvement in energy efficiency across our entire global refining and chemical operations by the year 2012. I’m proud to report, ExxonMobil delivered on this commitment.
Another important metric shown in this slide is hydrocarbon flaring. We continue to progress initiatives to reduce hydrocarbon -- hydrocarbon flaring associated with our upstream operations. Since 2008, we have decreased hydrocarbon flaring by nearly 40%. In 2012, hydrocarbon flaring resumed its downward trend and approached our best ever performance.
We reduced greenhouse gas emissions by about 9.5 million tons since 2008, that’s equivalent to taking 1.9 million cars off the road in United States. And finally, we continued progress in reducing other hydrocarbon releases into the environment, most notably in spills of oil, products, chemicals and drilling fluids.
Our marine organization which moved 1.8 billion barrels of oil and products in 2012 has gone more than three years with no hydrocarbon spills from company-operated or term chartered vessels.
Additionally, this is the first year in which cumulative spills were less than 1 barrel from spot 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 look at earnings. ExxonMobil led the industry in 2012 with earnings of $44.9 billion, an increase of 9% compared to 2011, reflecting sound operational performance, capturing of our integration advantages and value derived from our ongoing routine asset management activities. Meanwhile, earnings per share increased 15%, reflecting the added benefit of our substantial share buybacks.
ExxonMobil's upstream earnings per barrel were $19.27 in 2012 and averaged $18.33 over the last five years. While we are not satisfied with our current level of unit probability, we understand the reasons for our relative position.
Negative impacts to our metrics were anticipated when we made important long-term strategic decisions like the XTO acquisition and our entry into Iraq, and time will tell how these decisions ultimately playout in their deliver of long-term growth and earnings and cash flow.
I would remind you the red line represents an average of a broad array of quality oil and gas resources. With some barrels profitability well above the line and some well below. Our investment programs and asset management activities are all targeted to improve unit profitability.
We have plans in place to improve unit profitability and we’ll continue to capture benefits of our disciplined and consistent approach to cost management, operational excellence and technology applications, without compromising our ongoing commitments to operational excellence and risk management. We have a good record of achieving this throughout our history.
In 2012, ExxonMobil’s return on capital employed was an industry-leading 25.4%, about 7 percentage points higher than our nearest competitor. Over the past five years, ROCE averaged 24.4%, about 6 percentage points higher than our nearest competitor.
This industry-leading ROCE performance is despite low natural gas prices and ongoing large investments such as Kearl -- the Kearl oil sands project and our large development of the Papua New Guinea LNG project, both of which have yet to contribute our earnings.
The industry as a whole is in a period of high capital investment. All anticipated to meet the world’s growing need for energy and we're making the necessary investments through the business cycle to position ExxonMobil to meet those needs and sustain strong resilient long-term performance.
Under these considerations, our ROCE performance exceeds competition due to our consistent discipline investment approach, our industry-leading project execution capabilities, proprietary technologies and the advantages of our integrated model.
Another value -- another measurable value created through strong financial and operating performance is the cash flow remaining after fully funding attractive investment opportunities.
Over the past five years ExxonMobil generated $138 billion of free cash flow. This almost equals the combined total of our competitors. Consistent, robust free cash flow provides capacity for unmatched shareholder distributions and underpins a strong financial position.
Let’s now look at shareholder distributions. Since the beginning of 2008, ExxonMobil has distributed $145 billion to shareholders, including $44 billion in dividends and $101 billion of share repurchases to reduce shares outstanding.
These industry leading shareholder distributions were higher than that of our competitors combined. Since the time of the Exxon and Mobil merger share repurchases have reduced shares outstanding by more than 35% from 7 billion shares in the year 2000 to 4.5 billion share at the end of 2012. In addition during that period, we issued and repurchased all the shares utilized to acquire XTO.
We've increased our per share dividends by 59% since 2008. This included a 21% increase in the per share dividend in the second quarter of 2012 and mark the 30th consecutive year, ExxonMobil has increased the dividend on a per share basis. Unmatched shareholder distributions delivered a distribution yield above the competitor average.
Over the past five years, shareholder distributions have delivered a total yield of 29% yield exceeding the nearest competitor by more than 6 percentage points over the same period. ExxonMobil's average annual yield is 7.2% over last five years exceeds the competitor average of 4.7% and that of each competitor in the group.
During this period of significant shareholder distributions, ExxonMobil has maintained a strong financial position, while funding attractive investments at record levels and repaying debt.
Distributions through share repurchases have also enhanced the per share interest in ExxonMobil’s underlying business. Each share of ExxonMobil's owns 21% more production volumes today then it did in 2008. Since, 2008, ExxonMobil has delivered annualized production per share growth of 5% more than 3 percentage points higher than our nearest peer.
As we've said for many years, financial results and stock market returns, particularly for highly capital intensive industry such as ours are best viewed over long period of time, and the industry like ours requires a sustainable risk management of cash and capital, and long cycle terms for investments to deliver results.
ExxonMobil has generated greater shareholder value in the broader market and greater value than average of our competitors over the last 10 and 20 year periods. Over the past decade, the S&P annualized return was 7% versus ExxonMobil's annualized return of 12%.
Now to provide some context for discussion of our plans across each of our business lines, upstream, downstream and chemicals. I want to first describe factors influencing the industry and the business environment.
The global business environment continues to provide a mix of challenges and opportunities. Global economic recovery is progressing at a slow pace, and the OECD growth remains sluggish with fiscal and financial risk persisting in Europe and to a lesser extent here in the United States.
On the other hand developing nations are showing signs of more stable growth following a slowdown in 2012. Economies in the Asia-Pac region continued to outpace the U.S. and Europe.
Despite some areas of near-term economic weakness, we still anticipate that over the next 30 years global economic output will more than double. As people around the globe pursue and achieve opportunities to improve their standard of living.
To realize these long-term growth nations must maintain appropriate and sustainable regulatory frameworks to support investments that enhance security, economic competitiveness and the environment.
While today's economic and business environment presents a unique set of challenges, it also presents opportunities. And ExxonMobil remains well-positioned to help meet long-term global energy and petrochemical demand, which is likely to grow significantly.
By the year 2040, the extent of our most recent outlook, the world's population is expected to increase by close to 2 billion people and with it expanding economic prosperity. Coincident with these changes ExxonMobil’s 2013 outlook for energy indicates global energy demand is likely to grow about 35%.
Even as economies continued to become more energy-efficient. Ensure reliable and affordable energy supplies to support this growth safely and with minimal impact on the environment will require broad-based economic solutions.
The bar chart on the left shows projected growth from the beginning of 2010 to the year 2040 by energy supply type. Oil, gas and coal are the most widely used fuels today around the world, providing about 80% of supplies. While we anticipate a gradual shift in the global energy mix, consumption of oil will remain most prominent as the fuel of choice to meet expanding transportation needs.
Demand for natural gas will rise by about 65% and will become the second most widely used source of energy. Natural gas is increasingly recognized as a reliable, affordable and clean fuel for a wide variety of applications and its growth to the supported by advanced technologies that are unlocking abundant resources and advancing widespread utilization.
We expect global demand for natural gas, nuclear and renewables will rise at a faster than average energy demand growth rate, led by this ongoing shift in mix to meet growing power generation requirements.
Obviously, energy use will differ for the developing countries, with higher growth rate economies than for the more mature developed countries. And as shown on the left, energy demand for economies of the non-OECD countries is expected to grow about 65%, to support anticipated growth an economic output of more than 250%.
On the right, a very different picture, as expected in the developed economies as demand remains relatively flat. Now this outlook is despite the fact that economic output in these countries is likely to be up by 80% between now and the year 2040.
Over the period, we see a shift in the mix of fuels. Oil demand will continue its gradual decline, reflecting significant fuel economy gains in the motor vehicle fleet and other areas less carbon intensive fuels will become more prominent, with natural gas expected to meet about 30% of OECD energy needs by 2040. In total, global energy needs are likely to rise about 35% with Asia-Pacific accounting for close to 60% of this increase. If we loose a sound I’ll go back, okay.
We expect that oil and other liquid fuels will remain the world's largest energy source in the year 2040, meeting about one-third of energy demand. While conventional crude oil production will remain the most significant source of supply over this period. Demand growth will be met by development of new sources through the application of advancing technologies.
As you can see in the chart on the left, the most significant gains are expected from the global deepwater resources, which more than doubled over this period. We expect important growth from oil sands and tight oil resources with their share of liquid supplies exceeding 10% by the year 2040.
Natural gas liquid supplies expected to increase as a byproduct of the significant growth in natural gas resources. On the right, we see natural gas supply and demand. An increasing share of global natural gas demand is expected to be met by unconventional supplies such as shale and other type rock formations, which today are rapidly becoming conventional.
By the year 2040, such unconventional gas will account for about one third of global production, up from less than 15% in the year 2010. The oil and gas outlooks made clear the important role of unconventional capabilities along with expanding existing deepwater and ongoing improvements in conventional capabilities.
By the year 2040, we expect energy demand for the transportation sector to increase more than 40%. Despite this robust demand outlook for fuels products, we still anticipate a challenging downstream business environment. This view reflects an increase in global industry refining capacity, development of alternative fuels and ongoing energy efficiency gains.
As shown on the chart, the transportation product mix is changing. We expect a continuing shift of the transportation fuel mix toward diesel with continued gradual declines in demand for gasoline. In fact, we expect diesel will account for about 70% of the growth in demand for liquid fuels for transportation. This largely reflects high growth rates in developing countries as greater truck, rail and marine transportation support expanding economic activity.
Advancements in basic and specialty chemicals have enabled the development of versatile and lower cost materials which replace traditional applications of paper, glass and metal. These substitutions offer enhanced product characteristics often bringing sustainability benefits, including savings and energy, water and raw material use. As such global chemical demand grows at a faster pace in GDP as people seek higher standards of living, move up the value chain and purchase more household and packaged goods manufactured with chemical products.
Two thirds of the chemical demand growth is in Asia-Pacific as the region acquires chemical feedstock products to manufacture goods for domestic and export markets. China alone is expected to represent over half of global demand growth with its rapidly growing middle class and expanding purchasing power. Other parts of the world will also have grown chemical demand but at a slower pace.
In the decades ahead, the world will require dramatic expansion of reliable and affordable energy suppliers to meet growing demand. The scale of the challenge is enormous and will require pursuing all economic options to expand supplies in ways that are safe, secure and environmentally responsible.
A steadfast commitment to the development of new energy technologies is required to expand supply of traditional fuels, advance new energy sources and capture ongoing energy efficiency opportunities. Access to high quality resources in an unprecedented level of investment will be required to develop resources with the advanced technologies that will expand and diversify supply.
Governments can play a major role by maintaining sound and reliable policies that mitigate investor uncertainty. This includes policies that provide access for development of new oil and gas resources and provide open trade to allow businesses and people to prosper and grow their economies.
We 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.
Now, next I’m going to cover some key elements of our corporate strategy that are common across all of our business lines. Our implementation of this strategy will be covered in each of the respective business overviews.
ExxonMobil's mission is to be the premier petroleum and petrochemical company in the world. To deliver on that mission requires each of our three business lines, upstream, downstream and chemical to be premier among their peers.
Some of the key aspects of our strategy to achieve this mission are shown on the slide. Our relentless attention to operational excellence supports safe, reliable and efficient operations. Reducing risk by applying the highest operational standards is embedded in ExxonMobil’s culture.
We develop and employ systems to consistently apply the high standards leading to best-in-class operating performance. We're uniquely positioned to fully harness value across our businesses because of our integration.
We leverage the complementary nature of each of our businesses to capture the maximum value of every molecule that moves through our hands. At ExxonMobil, we employ discipline processes in everything we do, from initial resource capture through capital project development, to our ongoing operations.
Within each of our businesses, the quality, the size and the diversity of our portfolio provide unique competitive advantages to ExxonMobil. We have a continued long-term focus on maximizing profitability and returns from every asset in our business lines. This long-term approach has positioned each of our businesses to be at the top of their respected areas of competition, which allows us to maximize long-term shareholder value.
So now let me provide you an overview of the upstream. The strategies we have in place are designed to deliver long-term value. These strategies have stood the test of time as we have faced ongoing challenges, developing new resource types and new markets.
Through execution of our strategies and plans, we have developed industry-leading capabilities across all emerging resource types and opportunities, which include the deepwater, liquefied natural gas, heavy oil in oil sands, the arctic and unconventionals. We have a successful history of bringing on best-in-class resources and are well-positioned for sustained growth.
We are confident that consistent execution of these strategies and our relentless focus on profitability will continue to differentiate us from others. Now, let me begin with a brief overview of our capabilities across the major resource types.
In each of these, I’m going to give you an example of how these types of resources develop. It was not long ago that the deepwater was beyond the industries reach. Today, though exploring, developing and producing in deepwater has become very much a base part of our operations.
Approximately 10% of our liquids production today comes from deepwater assets in West Africa, the North Sea and the Gulf of Mexico. It took years to bring much of this production online and shown on the slide is an example, such as Angola.
Our exploration organization identified prospective deepwater acreage in the late 1980s and early 1990s. And by 1996, we had our first deepwater discovery. Over the course of the next decade, we followed a delivered approach to transform what was once a frontier play into a world-class profitable business.
Overcoming technological obstacles, developing operational practices, such as design one, build multiple, initiating satellite field tieback developments and developing a world-class Angolan national workforce. From the beginning, Angola operated assets were developed employing best practices in design, operations and safety and developed and institutionalized those areas from our many years of operating experience.
The result is evident in Angola Block 15’s outstanding safety performance, equipment integrity and facility reliability. In fact, over the past three years, ExxonMobil operated deepwater assets have delivered 7% higher uptime than similar assets operated by others.
ExxonMobil’s operated uptime on our assets in the deepwater were 93% compared to operated by others uptime of 86%. Continued success in the deepwater environment depends on ongoing technology improvements and advancements. You can never standstill.
Our Subsea Technology Organization has completed testing of seven new technologies, which will enable pursuit of resources and even deeper and more challenging environment. And they are progressing an additional 22 technologies to support our efforts and future pursuits. These capabilities are particularly important in the deepwater Gulf of Mexico.
The deepwater Gulf is an active region for our explorers and developers. ExxonMobil currently holds interest in 355 blocks or about 1.7 million net acres. We have four important projects underway which are shown on the slide.
The first two are Lucius and Hadrian South, both are in execution and progressing toward the startup in 2014. Lucius is 100,000 barrel per day development with a new build spar floating production system. Hadrian South is a 300 million cubic feet per day subsea gas development, which will be tied back to the Lucius facility.
The other two projects are Hadrian North and Julia. Hadrian North is a 100,000 barrel per day development with a new build semi-submersible floating production system. Two appraisal wells were drilled in 2012 with an additional appraisal well currently in progress. Design engineering will follow our appraisal program.
For the Julia project, we are pursuing a phased development concept. The initial development will be a six well subsea tieback to the Jack/St. Malo host facility with anticipated capacity of 30,000 barrels per day. We expect a full funding decision on this development in the middle part of this year.
As these projects progress, we continue on active exploration program. We added 66 new blocks in the deepwater from two Gulf of Mexico lease sales conducted in 2012. We have an active seismic acquisition program and are applying in-house proprietary processing techniques, enabled by expanded high-performance computing capability.
These data and analysis are key to prospect generation and to sustain a planned, active, wild cat drilling program. Three prospects will be drilled in 2012, including Phobos, Thorn and Maui in the deepwater subsalt of the Gulf of Mexico. Supporting our and the industry’s activities in the Gulf of Mexico, the industry’s Marine Well Containment System continues moving forward.
We expect to have the next components of the system ready for deployment if needed by the end of this year. This will include two marine capture vessels with a combined capacity of up to 100,000 barrels per day.
Now, I’ll turn to another resource that shows the impact of successful execution of our proven approach to liquefy natural gas. This chart is similar to the characteristic long timelines to deliver meaningful results that are seen on earlier slide for deepwater.
In this case, we have the timeline establishing our now significant position in LNG capability, which was created from our partnership investment and innovations in Qatar. Today, we produce over 650,000 net oil equivalent barrels per day of LNG, accounting for approximately 15% of ExxonMobil's total production volumes.
Over the past decade, we have tripled our LNG production. This is doing large part to our successful partnership with Qatar Petroleum. Together, we are commercializing the world's largest non-associated gas field. Through our joint venture efforts with Qatar petroleum, we have successfully deployed high-impact technologies to increase efficiency and decrease costs.
Through our integrated capabilities in the upstream supply and marine, we have captured economies of scale by building LNG trains and ships with record capacity. From the world's first 3.3 million tons per year LNG facility in 1999 at Qatar gas, we extended engineering and technology to build the world's first LNG facility, capable of 7.8 million tons of production in 2008.
We also achieved industry first elsewhere in the value chain with the development of the next-generation largest LNG tankers in the world, the Q-Flex and the Q-Max LNG ships and the world's first offshore concrete gravity-based LNG receiving and regasification terminal off the coast of Italy in the Adriatic Sea. These successes have enabled -- been enabled by innovative applications of existing technology and selection and development of step-out liquefaction technology.
Utilization of common infrastructure and shared facilities at Ras Laffan City, along with application of our global contracting, procurement and project management capabilities and again the utilization of our design one, build multiple approach, captured synergies and make Qatar LNG trains and delivery systems the most competitive in the global market today.
As a result of our first mover position in Qatar in the 1990s, we have expanded and entered important LNG markets around the world. Our successes in Qatar have been built upon to develop new sources of LNG in Australia, supporting our partners in the Gorgon Jansz LNG development and in our evaluation of Scarborough LNG project. In North America, early planning activities are underway for potential LNG export project in Texas, Alaska and Canada.
Next, I’m going to provide additional information on our next LNG project nearing start-up Papua New Guinea. In Papua New Guinea, we're developing a high quality 9 trillion cubic foot resource. The project includes a 430 mile pipeline to transport gas from the field in the Highlands to a two-train 6.9 million tons per year LNG plant near Port Moresby.
Construction activities are well advanced as you can see in the picture. And the project is on schedule for start-up in 2014. In 2012, ExxonMobil drilled P'nyang South-1 exploration well, which encountered significant hydrocarbons, holding potential for additional gas reserves.
Required more than 55 miles of 2-D seismic in 2012 and planning is under way to acquire additional data in 2013. This seismic data will guide future exploration activities in support of a potential per train. Progress of PNG is another example of our strategic, disciplined and integrated approach.
Now, I’ll turn to another resource type that demonstrates the results of our long-term planning and strategic execution, oil sands and heavy oil. Heavy oil and oil sands assets provide long plateaus of oil volumes and we have a long experience in the oil sands and heavy oil, dating back to the 1960s when lease acquisition and pilot activities in Cold Lake first began.
The first commercial in situ development of bitumen began at Cold Lake, which started up in 1985. Since the Cold Lake project’s inception, continuous improvements and advances in technology have more than doubled the expected recovery from 15% of the bitumen in place in the 1970s to over 40% today, an addition of hundreds of millions of barrels of resource recovery.
During this period, we’ve also reduced freshwater usage per barrel by 90%. Important advances in bitumen in situ recovery technologies have been an ongoing joint effort by ExxonMobil and Imperial Oil, with current focus on the use of solvents to improve bitumen recovery, access undeveloped resources and reduce greenhouse gas emissions.
Our patented liquid assisted steam enhanced recovery or laser technology, first commercially applied at Cold Lake increases bitumen recovery rates by adding a small amount of solvent to existing high-pressure cyclic steam injection applications. We are testing underway on a cyclic solvent process field pilots, scheduled to start up in 2014.
Results from precommercial trials in pilots of these technologies will allow us to optimize long-term resource development plans and increase bitumen production and value. ExxonMobil and Imperial Oil will continue the evaluation of our very strong oilsands portfolio through ongoing seismic and coral drilling programs to define the next-generation of high-quality mining and in situ projects.
Our experienced at Cold Lake give us confidence. The technology and operational excellence can grow the reserve base and bring greater returns to shareholders. We are applying these learnings to our premier portfolio of heavy oil assets in Canada.
The Kearl oil sands project in Canada are developing a world-class resource in Northern Alberta of more than 4 billion barrels. The Kearl initial development is currently in the process of starting up and we expect first production this quarter. The effective application of technology is at the core of this project. An innovative and proprietary process generates pipeline quality bitumen that will be blended with diluent for shipment.
This process eliminates the need for a costly onside upgrader and produces a crude oil with a green house footprint on part with the average barrel of crude oil refined in the United States. Initial production is projected to be approximately 110,000 barrels of bitumen per day with future debottlenecking and expansion increasing production to 345,000 barrels a day. The long-term growth production plateau is projected to extend for 30 years.
The Kearl next phase expansion project is already underway and it’s approximately 30% complete, putting us on target for 2015 start up. Together, the initial development and the expansion projects will develop 3.2 billion barrels. Another resource area with growing importance to ExxonMobil is the Arctic.
For ExxonMobil, our presence and our interest in the Arctic are not new. We have a 90-year history of Arctic technology innovation. This slide illustrates that history, which dates back to the 1920s and the discovery of the Norman Wells field.
Other highlights in our long history include the discovery of Prudhoe Bay in 1968, the construction of the Trans-Alaska Pipeline in the 1970s. Exploration drilling of the 1980s that employed man-made gravel islands and ice-spray islands, installation of the first and only iceberg resistant gravity-based structure at Hibernia in 1997.
The Primorye tanker ice trials off the coast of Russia's Far East in 2002, the installation of the Orlan platform at the Sea of Okhotsk was stocking more than 2005. The month long iceberg survey offshore Labrador in 2012. ExxonMobil is well-positioned to leverage this leadership to take on the extremes and the new opportunities in the Arctic environment.
Exploration, development and production in these regions are subject to special challenges, including remote locations, short open water seasons, harsh weather, dynamic ice cover and fragile ecosystems. ExxonMobil’s comprehensive, integrated Arctic research portfolio addresses these challenges to unlock the potential of these energy-rich regions and develop new supplies in a safe, efficient and environmentally responsible way.
Arctic volumes comprised 8% of our current liquids production and our position to grow with the additions of the Arkutun-Dagi development offshore Sakhalin in Russia and Hebron development, offshore Nova Scotia. The Arkutun-Dagi project in the Russian Far East is well underway, with a successful installation this past summer of a gravity-based structure, and the location offshore Sakhalin.
In fact, the photo you see on the backdrop to the left or my right is the Arkutun-Dagi GBS on toe to its location offshore, the Far East. Topsize fabrication is 85% complete and the project is scheduled to start up in 2014. Arkutun-Dagi will have peak production of 90,000 barrels per day and is expected to recover over 630 million barrels of oil.
In 2012, ExxonMobil also started up the Chayvo onshore processing facility expansion to develop 130 million barrels of oil equivalent. The project came in three months ahead of schedule and under budget.
In Canada, we have another Arctic project moving forward, Hebron. The Hebron project was sanctioned in December of 2012 and is anticipated to produce more than 700 million barrels of oil. Execution is underway with detailed engineering, procurement and site work in Newfoundland with a gravity-based structure.
Now, turning to the unconventional resources, including tight oil. As these slide shows, we have holdings in a broad array of North American unconventional plays, many with liquids rich opportunities.
In Canada, we recently closed the Celtic acquisition, adding 650,000 acres of significant liquids rich resource potential in the Montney and the Duvernay reservoir. Adding this to our significant positions in the shale gas plays of the Horn River and Summit Creek, the Cardium tight oil reservoirs and our large Athabasca oil sands holdings in both in situ and the mined areas. We have secured significant resource potential, spanning more than 2 million acres of leasehold.
In 2012, we also completed $2.6 billion of strategic bolt-on acquisitions in the Bakken and the Woodford Ardmore, our fastest-growing liquids rich U.S. plays. And we also consolidated assets in the Permian basin, and other lower 48 areas into XTO's operating portfolio.
With North America accounting for the core of our global unconventional position, we expect to further improve the recovery of these resources as a result of the collaboration between ExxonMobil’s world-class researchers and technical and operations staff.
Now, let’s take a closer look at our liquids rich unconventional program, the fastest-growing segment of our U.S. operations. We continued to expand our position in the U.S. liquid rich plays. The chart in upper left illustrates our 2012 drill well inventory in three major liquids rich plays, the Bakken, the Permian and the Woodford Ardmore.
As you can see, it has nearly doubled year-over-year to 11,000 drillable locations. The largest increase is in the Ardmore Basin Woodford shale plays of southern Oklahoma, where our position increased to more than 270,000 acres due in part to a strategic acquisition that added almost 60,000 acres.
With 12 drilling rigs running, this is our most active unconventional play. In 2012, we progressed delineation of the Woodford, perform spacing test and began pad development across the core area of the acreage. We also successfully completed the first test of both the Marietta basin to the Southwest and the overlying Caney Shale of the Ardmore Basin. The results of both drilling and acquisitions additions have now increased the Ardmore's total resource estimate to more than 0.5 billion oil equivalent barrels, or more than doubled the 600 million oil equivalent barrel we shared with you at this time last year.
As shown, this has the potential to generate deep production of more than 150,000 oil equivalent barrels per day and we continue to evaluate further upside in the Woodford and other formations. Ardmore production more than doubled in 2012 to roughly 19,000 barrels of oil equivalent per day, an increase enabled by the expanding, gathering and processing infrastructure in the region.
In the Bakken, net equivalent production increased by 41% in 2012, principally on the heels of a successful drilling program, yield an increasing per well rates and turning more wells to sales. Our Bakken resource estimate increased to just under $1 billion oil equivalent barrels by the end of the year, partly due to a strategic acquisition that increased our production and acreage in the play by more than 50%.
In the Permian Basin, strong legacy holdings in this oil province support a leading position of more than 1.5 million acres of leasehold and 93,000 net barrels oil equivalent daily production.
Let's now look at how operational excellence in these unconventional plays continues to improve their economics. Operational efficiency and technology enhance unconventional value by delivering higher recoveries and lower development unit cost. In our more mature shale play, the Barnett shale, we are capturing increasing efficiencies through pad drilling up to 20 wells per pad and optimized completion practices to reduce costs.
The chart shows a consistent and dramatic increase in the wells drilled per rig year in the Barnett since 2006, an average increase of 17% per year to just below 30 wells drilled per rig year in 2012. This increase has occurred despite the rising complexity of the drilling due to longer reach laterals, which have generated a 13% increase in the measured depth of wells drilled over that same time period. These efficiencies translate into lower drilling cost, which have declined 8% per year in the Barnett over the past five years.
In the Haynesville, we are optimizing completions by adjusting the perforation clusters, the spacing of frac stages and proper concentration. As shown in the lower graph, which illustrates the production for completed foot of reservoir, the optimized Haynesville completions are performing measurably better than the traditional completions, with the potential improvement on expected long-term recovery of between 20% and 50%.
Now, let's examine our near to medium term production growth, the resource base and the major projects that stand behind that growth. ExxonMobil's upstream portfolio includes high-quality exploration opportunities, an industry-leading resource base, a broad range of world-class projects and a diverse set of producing assets. We continued development of our resource base. We will deliver additions of over 1 million net barrels of production per day by 2017.
Most notably, we are growing liquids production and liquid rich gas volumes. Let me begin with a description of the resource base. ExxonMobil has a resource base of over 87 billion oil equivalent barrels, which includes proved reserves plus other discovered resources that are expected to be optimally commercialized.
We review the resource base annually, taking into account new discoveries, asset acquisitions with discover volumes, field revisions, production and asset sales. The resource base is large, it’s diverse and it contains a well balanced portfolio of holdings.
The bar on the left shows that about half of the resource base is comprised of conventional, deepwater, Arctic, LNG assets and assets that contain asset or SAR characteristics. It is split equally between gas and liquids as shown in the middle bar. We also have provided a description of commercial maturity.
As you know, we currently have just over 25 billion oil equivalent barrels of proved reserves, but an additional 27 million barrels in design and development stages. The remainder of the portfolio, approximately 35 billion oil equivalent barrels, contained the resources for future developments.
This undeveloped category contains a variety of assets from both recently discovered that have not yet been fully apprised, such as they can reach the design stage to those more strategic assets that are being held for future developments. Each year, we add resources to this category. And from there, we select those to move forward to design and development, taking into consideration such factors as profitability, holding cost and capital investment requirements.
And next, I want to briefly discuss our reserve replacement and resource additions last year. This slide shows reserve replacement and resource additions over the past five years. For the 19th consecutive year, we replaced more than 100% of our production. In 2012, we added proved oil and gas reserves, totaling 1.8 billion oil equivalent barrels, including a 174% replacement ratio for crude oil and other liquids.
At year-end 2012, proved reserves totaled 25.2 billion oil equivalent barrels, which was comprised of 51% liquids and 49% natural gas. During 2012, we added over $4 billion oil equivalent barrels to the resource base. Our by-the-bit resource additions were over 2.9 billion oil equivalent barrels, the highest by-the-bit additions since the Exxon-Mobil merger. The total resource base now stands at 87 billion oil equivalent barrels. A strong diverse resource base supports not only today’s production volumes but positions volumes for future.
Turning now to where these near-term volumes are going to come from. ExxonMobil has a large geographically diverse portfolio 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 slide.
The diversity and scale of our project portfolio supports ExxonMobil's investment selectivity to deliver projects that are robust and profitable over a broad range of economic conditions.
This slide describes eight of the 31 major projects that we have started up or plan to start up between 2012 and 2017, 27 of which are liquids or liquids linked projects. In 2012, we started three major projects all in West Africa, including Satellites projects in Angola and Nigeria.
Within the next three years, we expect to start up 22 major projects, including Kearl and Papua New Guinea LNG. These projects provide ExxonMobil with a strong foundation for future production volume growth.
This chart shows the projected increase in net production from major project startups over the next five years. We anticipate adding over 1 million net oil equivalent barrels per day by the year 2017.
As shown on the chart in the blue and green shadings more than 90% of these additions are liquid or liquids linked volumes, about two-thirds contribute to a buildup in long plateau volumes. Our diverse project portfolio provides long-term growth.
So turning to our full production volume outlook. Now before discussing this year’s outlook, I do earlier reconciliation with last year's 2012 volume performance compared to what we expected at this time when we last spoke.
The 2012 volumes were 2.7% lower than what we expected when we share this outlook with you last year. About half of the variance was due to operational performance issues i.e. some facility integrity issues which we felt we need to deal with, with the balance the other half due to entitlement impacts resulting from price effects different price environment in the basis that we share with you last year, as well as the pace of our spending in Iraq, which was adjusted to accommodate the export capacity of the systems in Iraq.
Turning then to this year’s outlook. This chart shows the total upstream production outlook through the year 2017. We anticipate volumes will grow 2% to 3% per year from 2013 to 2017, with significant contributions from liquids.
You’ll note that our projections are based on 2012 average Brent price of $112 per barrel, another magic about that price just happen to be the 2012 average, so we’ve got to give you some basis.
Of course, the actual production in any specific year can vary above or below what is reflected here due to variables such as price, quotas, divestments, which we don't share with you in advance, weather, regulatory changes, geopolitics and unplanned downtime in our operations, as well as unplanned downtime in those properties that are operated by others.
As shown by the green line on the chart, the liquids outlook is up approximately 2% in 2013 and it is expected to be up 4% per year through 2017. Now shown by the red line on the chart, gas production will be down approximately 5% in 2013 after which it is expected to increase by about 1% per year over the period. Overall, liquids and liquids linked volumes are projected to be up 3% to 4% per year during the period.
Total production will decline about 1% this year in 2013 versus last year. The projection for 2013 is lower than presented last year, due in part to lower anticipated dry gas volumes in North America, as well as some minor slippage to startup of two projects timing this year.
Now I’ll share a view of the opportunities that have us well-positioned to deliver on the long-term growth, essential the long-term growth is developing and maintaining a balanced portfolio of opportunities, develop profitable reserves over the decades to come, balance in terms of risks and balance in terms of resource type.
With our global approach we identify, assess and test a range of profitable opportunities from large high risk prospects that will take some years to evaluate and test, and if successful, move the development to those resources and more mature areas that while more modest in size may result in near-term profitable volumes.
This past year is a good example of that approach. Last year we proved up two new plays, the first in the deepwater Black Sea offshore Romania with the Domino wildcat and later in the year with three wildcats offshore Tanzania.
We have a robust inventory of wildcat prospects across a variety of resource types conventional and unconventional, deepwater in the Arctic and we’ll be advancing these opportunities in the very near-term.
We’ve increased our acreage position across a range of proven and emerging plays that will maintain a robust inventory of prospects in the years to come. The next few slides will detail some of this.
So let me begin first by identifying the new play test, which are highlighted by the yellow dots on the map. Now these are opportunities in under explored basins in new plays, they offer significant potential if there are successful. But given their nature they carry higher uncertainty and risks than other opportunities in the portfolio.
The Dunquin prospect is in a basin located offshore Southwest Ireland and water depth of approximately 1600 meters. We expect to spud the Dunquin one wildcat during the second quarter of this year to explore the potential and targeted carbonate reservoirs.
You maybe familiar with the Brugdan 2 well in the Faroe Islands. Our partners started drilling this wildcat but suspended it late last year due to the onset of winter weather. We anticipate resuming operations later in 2013 or 2014.
In Guyana, we hold 3 million net acres in the deepwater. In late 2012 and early 2013, we completed the acquisition of two 3-D seismic surveys on this acreage and as mentioned previously, we have confirmed new plays most recently in Romania and Tanzania. I’ll speak to these in more detail in a moment.
So now adding the green dots on the slide, these highlight opportunities and what we characterize is proven plays or areas where exploration discoveries have already been made and so we know we have working hydrocarbon systems.
These opportunities still carry a range of risks and uncertainties, but not to the same degree as a new play test. Areas such as the Gulf of Mexico, Norway, West Africa and the Northwest shelf of Australia fall into this category.
And this year as a result of our success we have moved both Romania and Tanzania now to the proven plays. We intent to remain active in the proven plays, the success is here have capability to deliver volumes in a shorter period of time.
Now the orange dots highlight the most significant areas where we are exploring four confirming, producing unconventional reservoirs. I’ve of already described our leading position in the unconventionals in North America.
Many of our acreage positions elsewhere are located in basins with existing hydrocarbon potential such as the West Siberia Basin in Russia, the Neuquen Basin of Argentina and the Middle Magdalena Basin in Colombia with access to significant existing infrastructure.
As we’ve previously announced, we anticipate initial drilling in West Siberia this year. In addition, we are active in both Argentina and Colombia, where our acreage is over 1.3 million net acres. In 2012, we drilled five wells in Argentina and one well in Columbia, and plan to drill additional wells this year.
In both countries, we have encouraging results from our drilling activity, but it is still early in our valuation plan. The key to understanding commerciality of these opportunities is to determine producibility, which often requires production data from longer term test.
We’re leveraging XTO's capabilities from experience in North American unconventionals to rapidly evaluate these global opportunities. As you can see from the map, our portfolio of high-quality resource opportunities include both resource diversity, as well as geographic diversity and has a broad range of probabilities of success.
So now let's look at some of our near-term exploration activities in more detail. The Kara Sea area in the Russian Arctic is an extension of the prolific West Siberian Basin. The license area is approximately 31 million gross acres in size. Agreements were signed in 2012 defining the roles of ExxonMobil and Rosneft in a new joint venture.
During 2012, 2-D and 3-D seismic data were acquired along with data to support drilling site clearance, ice, met ocean and environmental studies. Numerous leads have been identified on the blocks and we anticipate that the first, the University prospect located in 70 meters of water will like be drilled.
In February of this year, we expanded the strategic cooperation agreement with Rosneft to include an additional 150 million acres of exploration acreage in the Russian Arctic. The agreement includes plans to explore seven new blocks in the Chukchi, the Laptev and additional areas of the Kara.
The 108 million acres we are now working with Rosneft which include the original 31 million acres in the Kara Sea are equal to roughly 6 times the total leased acreage in the Gulf of Mexico, an area greater than the size of Texas.
The blocks cover some world's most promising but least explored acreage in the world. The enormous potential of the Russia Arctic will be explored and developed in the most efficient manner through a combination of ExxonMobil's Arctic expertise and Rosneft knowledge and experience operating in the region. With Rosneft, we are committed to using global best practices and state-of-the-art environmental protection systems for operations in Arctic.
Now as part of the expanded agreement, Rosneft will also have the option to acquire 25% interest in the Point Thomson development on the North Slope of Alaska. And we've entered into a memorandum of understanding to also evaluate the viability of an LNG development in the Russian Far East. The expansion of our strategic cooperation agreement illustrates the strength of the partnership between Rosneft and ExxonMobil.
Now during this past year we drilled a successful exploration well on Domino prospect in the Neptun Deep Block offshore Romania. This Block is approximately 2 million gross acres. This discovery proved a new play for us and derisked a number of prospects for further exploration. We are acquiring new 3-D seismic data and developing plans for additional drilling later this year or next.
The Tuapsinskiy Block in the Russian portion of the Black Sea is approximately 3 million gross acres in size. 3-D seismic is currently being processed and we expect to drill our first exploration well with Rosneft on this Block late next year.
In August of 2012 an ExxonMobil led consortium was announced as the high bidder for the Skifska Block in Ukrainian sector of the Black Sea. The Block is over 4 million gross acres in size. We’re currently negotiating the PSA on the Block and anticipate exploration activity once agreements are finalized.
During 2012, we drilled three successful wells in Block Two offshore Tanzania, the Zafarani-1, the Lavani-1 and the Lavani-2. These wells proved up the Paleogen play as well as lower Cretaceous play, up to 9 trillion cubic feet a recoverable gas has been discovered to date on Block Two.
The Zafarani-2 appraisal well is currently being completed. Additional 3-D seismic acquisition commenced in the fourth quarter of 2012. This data will be used to further assess the undiscovered potential of the Block.
In summary, ExxonMobil have a long track record of success in finding and developing a broad spectrum of resource types. Our capabilities coupled with our asset portfolio, positioned us well to deliver growth in the near-term, as well as the future.
Now next I want to turn the podium to Mike Dolan who is going to review our downstream and chemical businesses. Mike?
Thank you, Rex, and good morning, everyone. Over the next 20 minutes I’ll give you a focused look at ExxonMobil’s downstream and chemical businesses. As you heard Rex say earlier, we are very proud of our premier downstream and chemical businesses, which have a long history of delivering industry-leading results. I’ll start with some background on our global downstream and chemical businesses.
As you can see on this map, we have manufacturing assets in all major regions of the world and we make -- and we market our products in more than 150 countries. We are a truly global oil company that still values integration, while others have had similar models in the past, what differentiates us is our ability to extract value from that integration. As a result, we have leading positions in the areas we do business.
We are largest global refiner. We are the largest manufacturer of lubricant base stocks. We have one of the world's largest chemical companies with leading positions in many of our chemical business units.
We have invented or commercialized many of the catalyst, processes and products that have shaped the industry. We have unique modeling tools to maximize the value we can deliver from each and every molecule. And we are the most profitable downstream and chemical business in the industry.
Now underpinning the success of our downstream and chemical businesses are the ExxonMobil corporate values and constancy of purpose, as well as three distinguishing features.
First is operational excellence, including safety and environmental performance, reliability and efficiently utilizing our asset. ExxonMobil drives to be best-in-class in each of these important operational parameters.
Flexibility of our large integrated operations along with comprehensive optimization tools create business resilience and the ability to capitalize on latest changes in product demand or feedstock pricing. Proprietary technologies enable this optimization and also enable development of new high-valued products both in downstream and in the chemical business.
The second differentiator is our industry-leading portfolio which is the best overall collection of assets in our industry. In addition, we have a disciplined approach to managing our assets. And we have a healthy pipeline of attractive projects to improve and selectively grow our business.
The third key area that sets us apart is our superior financial performance. We have maintained best-in-class return on capital employed throughout the business cycle. Over the last five years, our downstream and chemical businesses generated $50 billion of earnings. More than net of the shale BP and Chevron downstream in chemical businesses combined.
Now, let me say a bit more about each of this. The foundation of our success is safe and reliable operations. Without this, we would not be able to focus on higher value activities that drive industry-leading results. We rigorously benchmark our assets internally and externally to identify gaps to best-in-class and cost-effectively implement appropriate gap closure plans.
For example in chemicals, over the last seven years, our steam crackers have on average run 1 to 2 percentage points higher operating rates in the competition, resulting in more product to sell and millions of dollars of additional earnings. With reliable operations and our scale, we can concentrate on structural improvements that translate to best -- to industry best cost positions.
In Solomon benchmarking studies since 2004, our refinery unit cash operating expenses have consistently been 10% below the industry average. Our major assets are pacesetters and among the most efficient in the industry.
A key enabler of operational excellence is technology. Our process and product technology allows us to capture market opportunities and manufacture a growing range of high-value products by enabling our plans to continuously improve reliability yield in costs. For example, based on 1000 benchmarking, our aromatic plants require 20% less energy per unit of production than the industry average.
Now, earlier I said that operational excellence includes how we maximize value through flexible integrated assets, and constant optimization, no matter the industry landscape. I’ll next show you a few such examples.
Against the backdrop of unconventional crude, oil and gas growth in North America, we are maximizing value through our integrated and flexible refining circuit. As you are aware, industry logistical constraints have caused such unconventional crudes to be available at lower cost to nearby refineries, especially those in mid-continent region.
In this regard, we are an industry leader in equity refining capacity in the mid-continent area from Canada to the United States as shown in the graph. At around 600,000 barrels per day, we are comparable to Marathon Petroleum and exceed other competitors in refining capacity in this profitable region.
We are processing essentially all advantage crudes in our mid-continent refineries driving strong earnings of these sites. Looking ahead, we are planning incremental investments at our refineries to increase our North American crude processing capacity, as well as enhancing our logistical capabilities to further capture opportunities.
The key message which I would like to share with you here is that with our balanced portfolio and integrated and flexible system, we are well-positioned to benefit from margin opportunities presented by the dynamic market environment, the North American unconventional crude growth being just one such example.
Let me talk next about the U.S. Gulf Coast, where we have significant refining capacity. We have a flexible and integrated system that can process both light and heavy crudes. We have been expanding advantaged North American crude runs both heavy and light as shown on the graph. We are currently unconstrained that our Gulf Coast refineries to run more advantaged North American crudes if economics justify.
However, the constraints lie with industry logistics infrastructure, which will take time to catch up with production growth. In the meantime, we're taking strength -- we’re taking steps to strengthen our own supply logistics and have secured pipeline commitments to place more advantage crudes in our refineries. As you can see, we have more than tripled our advantage crude processing over the past couple of years. And we continue to pursue opportunities to further increase such value capture.
In addition, we are also increasing crude by rail and barge, where it is economic. We are confident that with our continual optimization flexible circuit and to bottlenecking capabilities, we’re in a very strong position to benefit further as industry logistics improve over time.
In chemical, we have also been able to capitalize on North American unconventional gas development. One of the primary co-products of gas production is ethane, which is processed in our steam crackers to efficiently produce ethylene, a key building block for chemicals and plastics.
With the rise of U.S. natural gas production additional low-cost ethane is available for chemical producers. Since 2007, the ExxonMobil earnings contribution from U.S. ethane feedstock has increased 17-fold. In the U.S., our capacity to process ethane is unmatched in the industry.
We have designed our plans with proprietary technology to run a wide range of feeds. We have access to ethane molecules via our integrated upstream, downstream chemical business model. And we have optimization models and expertise to make rapid adjustments to production runs, depending on a variety of factors, such as feedstock pricing and product demand.
The true value of our model comes not from the use of ethane itself but rather the feedstock flexibility and growth of advantaged feed layers. So that no matter what the business environment we expect to outperform any competitor in the industry.
Another strength of our downstream and chemical business is our ability to introduce new high-value products. Here's one example from our industry-leading lubricant business. We anticipate continued growth and lubricant demand with strong growth in the synthetic sector at about 6% per year.
We are the world's largest lube-based stocks manufacturer and the leading marketer of high-margin synthetic lubricants. With three times the base stock market position and more than twice the synthetics lubes market position as the competitor average.
We have also been pioneers in industry-leading lubricant technology throughout history. From the lubrication of the Wright Brothers first historic flight to the introduction of the first synthetic engine oil Mobil 1.
In the last decade, we have doubled the sales of high-value synthetic lubes growing at a rate higher than the industry growth rate. Our growth strategy encompasses new products, optimal sales channels and engineering assistance for our customers, resulting in more customer value.
In 2012, we again set sales records for our flagship synthetic products, Mobil 1, Mobil SHC and Mobil Delvac 1. The strong growth of Mobil 1 sales is shown on this graph.
On the chemical side, we benefit from a business portfolio that includes specialties such as synthetic rubber, adhesives, fuel additives and hydrocarbon fluids for a variety of end-users. Even within our commodity polymer business, we differentiate our product offering by applying proprietary catalyst technology to improve physical properties and performance.
These unique products grow faster than the standard industry alternatives and command a premium price because of the physical performance and sustainability benefits they provide to our customers. For example, our polymer resins in the latest five layer packaging film technology enabled a 20% reduction in raw material and energy use versus the best next technology while providing the same toughness.
Our differentiated premium products altogether have generated earnings that have tripled over the last decade. And with our recently completed and announced investments, we’re poised to further build on this trend.
The industry-leading operational excellence and high-margin product differentiation, I've just spoken about are complemented by strong and balanced portfolio. We have the best portfolio of assets among our competition. Our world-scale and industry-leading competitiveness enable us to supply all key growth markets around the world.
In addition to our portfolio of assets, we employ multiple sales and distribution channels chosen based on what is optimal for each country, from in-country presence to offshore models to distributors and alliances. Our global supply chain and expansive geographic reach allow us to cost-effectively supply product to all parts of the world.
And we continue to strengthen our portfolio through both investment and divestment. Our portfolio management process is disciplined and thorough. We divest when a buyer offers us more for an asset than its long-term value on our portfolio. We are patient and we sell assets only when it enhances shareholder value.
Over the last decade in the downstream and chemical business, we have divested or restructured our interest in 35 refineries and chemical plants, more than 6000 miles of pipeline, more than 190 terminals and more than 22,000 retail sides, with total proceeds of $21 billion.
Through the process, I have just described we have been successful in generating both income and cash and improving and strengthening our portfolio. In our time-tested disciplined approach to managing our portfolio, we’ll continue as an integral part of maximizing shareholder value.
Next, I’ll share with you some of the major investments we're making to grow and strengthen our portfolio. In the downstream, we continue to invest in increasing our capacity to produce higher value of diesel and lubricants.
One example is the Singapore diesel hydrotreater project, which will increase our capability to produce Ultra Low Sulfur Diesel to meet the growing Asian demand for this product. Other examples include expansion at our Finland and China lube oil blending plants which will increase our lubes manufacturing capacity in those countries by more than 50%, strengthening our ability to capture growth in markets like Russia and China. We are also developing several other high-value lube manufacturing investments to capture further opportunities in this growth business.
In chemical, we have recently completed a significant Singapore expansion which double steam cracker capacity of the site. In Saudi Arabia, we are working with our partner to construct a world-scale synthetic rubber and specialty elastomers plant to serve growing demand in the Middle East and Asia.
And most recently, we have filed permit applications for our major expansion of our Texas facilities with a new world-scale cracker and associated premium polymer capacity to capture the value of our own ethane molecules. In summary, we are managing a robust pipeline of attractive projects, which capitalize on our strength and captures high-value growth.
Now, ultimately we judge the long-term financial success of our business by return on capital employed. As you can see, our downstream and chemical businesses have a return on capital employed that is unmatched by competition at any point in the business cycle. In fact, our 2012 downstream in chemical return on capital employed is higher than the total corporate return for each of our key competitors.
Our leading financial performance is enabled by proven business strategies and resilient competitive advantages accruing our integrated model, feedstock flexibility and balanced portfolio. Our focus on operational excellence yield strong safety environmental performance as well as reliability benefits and cost savings.
And we continue to deliver fast growing high-value products based on proprietary technology. We have a dedicated high-performing workforce around the world. Our employees are the best of the best and their dedication produces the results I share with you today.
All of the above factors are driving our downstream and chemical business to structurally superior performance. And finally, our disciplined capital management process ensures we have the best asset mix in the business.
We continually upgrade the portfolio in thoughtful ways that build shareholder value. And we concentrate new investments on integrated assets with significant competitive advantages. Altogether, we have the best downstream and chemical business in the industry and we are well-positioned to grow our lead in the years ahead.
Now, I’d like to turn it back over to David.
Thank you, Mike. We will now take a quick break. I would like to limit it to 15 minutes. And after the break, Rex will provide an outlook on our investment plans as well as some closing remarks. And then we’ll have the Q&A session. So I would ask that everybody please plan to be back in your seats at 10:50 so that we can have a full hour of question and answer. Thank you.
If I could ask everybody to take their seats and we can pick back up. All right. If you take your seats, we’ll go ahead and get started because again we do want to allow full hour for Q&A today. So at this time, I like to go ahead and get started. And I'll turn the podium back over to Rex Tillerson.
Okay. Well, thanks David. Well, I hope and I have got a very brief wrap-up here. We heard you last year, you didn’t get enough time to ask questions. So we have fixed that this year. But I do hope with the material that we provided you -- that we provided you with some context, some understanding, some appreciation of what makes ExxonMobil successful in each of the businesses we operate. And it is back to what I said earlier that our mission is to be the premier petroleum and petrochemical company in the world. That means you had to be premiere in each of the business lines.
All of that, all of it is always has one sole objective in mind and that’s delivering superior shareholder value. Year-in, year-out, our big long-term shareholders need to know that’s what they could expect from us. We feel an enormousness of obligation to deliver that. And so everything we do is directed with a very long term due in mind.
Now, before we conclude the prepared presentation, I do want to give you a look at our capital investment outlook as I know that’s important for you. As I've mentioned before, ExxonMobil is committed to maintaining the financial flexibility necessary to pursue investment opportunities we judge to be attractive through the normal ups and downs of the economic and business cycles.
Each project is evaluated using a range of prices to support attractive returns across varying business environments. We anticipate an investment profile of about $38 billion per year over the next five years to position all of our businesses for long-term growth and sustainability.
Upstream investments shown in blue in the graph do continued to dominate. I would note that the $41 billion outlook for 2013 does include the $3.1 billion to recently close the Celtic acquisition. So if you back that out, it’s back to the $38 billion number that I mentioned earlier.
As demonstrated by our strong 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 each of our businesses. Our focus on disciplined, selective investments underpins our ability to deliver superior returns.
We are proud of our ongoing efforts to identify and develop new technologies that enable us to pursue and unlock value and be more competitive and more efficient. With the focus on operational excellence, we develop and deploy systems to consistently apply the highest standards leading to best-in-class performance.
And finally, we capture substantial value across our complimentary premier business lines through our integration. We built processes and systems that enable our organization to establish constancy of purpose to maximize the value of each molecule we produce. These strengths provide competitive advantages and allow us to continue maximizing long-term shareholder value.
Now, I will leave you with the key messages on the screen. I’m not going to read them for you, because I think we’ve touched all of them throughout the presentation this morning. In conclusion, we continue to deliver strong results and we are well-positioned to continue to do so over the long-term, as we execute our strategies across our various business lines.
So that concludes the prepared remarks. I’m going to invite my fellow members of the ExxonMobil management committee to join me over here and a little more comfortable seating for us and we will open it up to questions.
I would ask that you limit yourself to two questions. When we go around again, we’ll try to provide a lot more time this year. And if you have more, pick you to most important and if time allows we will try to circle back with people and give you a chance to do more. If you don’t, somebody is going to come take microphone away from you so.
Join me up here. Just like another day at the office, we always sit around the coffee table like this, counting chairs and just chat about things. Let me start over here taking.
Arjun Murti - Goldman Sachs
Thanks, Rex. It's Arjun Murti with Goldman Sachs. Just a question on the shareholder distribution, which you’ve noted have been very robust and you’ve always described the stock buyback as a flywheel, which we’ve interpreted to be dependent on commodity prices.
But it seems like even with Brent at $100 to $110, you are going to be dependent on asset sales to support this level of stock buyback. Is Exxon willing to take on debt? You have a very strong balance sheet, or does the flywheel also now includes an element of the CapEx is pretty high and so it could be reduced on that basis as well?
Well, that’s something that we will evaluate at the moment that we see cash and our expectation for cash balances to shift this into a decision of do we want to use the flywheel, curtailed the share buyback program or use some of the other alternatives you mentioned.
We don't have a -- I don’t have a particular view on that, because so much of that will depend upon -- first and foremost, we will pay the dividend. Second, our investment program and if anything going on that investment program, it changes the future cash needs. Maybe something has been delayed and maybe something has accelerated. Maybe something has had to change.
So there's not a formulaic answer to it. It very much is a question, when we kind of look at the cash flows and quite frankly, this is something I do on a quarterly basis, then I kind of decide and we leave it. And then, I’ll look at it again in the next quarter and it's really a judgment around, is investment program going like we expected it to and based on that on our expectations, so the cash to be generated over the next quarter or two.
Do we want to do something different? Obviously, the easiest, most immediate thing is to adjust that share buyback. And as you rightly pointed out in your question, we have always represented that that's how we use that. And so changing that flywheels momentum is more often or not going to be our first choice.
But as you say, it's not our only choice. It will really be driven by the investment program that's in front of us. Maybe we acquired something new, maybe we've got a new opportunity that’s going to add to that and we may choose to finance that using some of the other alternative. So that’s not a crystal clear answer for you, but it is the way I think about it.
Arjun Murti - Goldman Sachs
That’s great. And I think of a very quick follow-up. Just a clarification on the production outlook. I guess it doesn't include asset sales, doesn’t impact, include OPEC quota effects, prices can go up and down as it impacts. But the entailment hits has been kind of tough over the year where you’ve reach a profitability threshold and the volumes drop materially. Is that reflected in there, in the context of the $112 Brent, or could we all still suffer? You all -- we all suffer from those kinds of entailment hits, which are the tough ones?
Well, the impact of entitlements that were in that volume outlook, or what the impacts will be at $112 Brent, so obviously if it's -- if Brent prices are higher or lower that entitlement impact will change as well and we don't forecast prices. We just choose -- we choose Brent because it was the price on the day as a benchmark. And I think, as we described last year, obviously if you go to lower prices, the entitlement effects will reduce our volumes little higher. If you go to higher prices, there are more pronounced or they know, how they are. They may accelerate another trench change into the year.
And so, typically the higher prices result in a bigger entitlement debit, lower prices less. I think if you look at the mix of the entitlement in the total volume, it still there, it still has its impact, it’s been diminishing somewhat over time because the structure of the many of the asset development were under a different fiscal regime. It doesn't have quite that same effect. Although in Canada, as you well aware, you do have a rule -- sliding rule to trenches. So sometimes it’s best wealthiest capture in entitlement as well. Yeah, Doug.
Doug Terreson - ISI
Doug Terreson - ISI. Rex, Exxon’s return versus the peers in S&P 500 have been pretty strong, I think that one of your charts indicated. But it also seems that the broader evaluation maybe be slipping somewhat, which indicates that investors may have concern over the future growth and returns of the company.
So my question is, is it the same view that ExxonMobil, or the super majors were entering into a slower phase of growth of some sort and if so, what do you think that might be and either way, how would this outcome affect your thinking on strategy as it relates to your distribution yields?
Well, I think it’s certainly for us, but it is also characteristic of the industry and the majors if you want to talk about us as a group. And we've mentioned this over the past two or three years now. This very high-level of investment, capitalization of the resource base that we are all working on is the largest contributor to that.
We're just growing -- we are growing capital employed. We are growing the asset base more, more quickly than we are realizing the cash flow from discount about stripping and it has been and it has been for the last two or three years just these intense capital programs that we are all managing. And you can examine our competitors. They are doing the same thing. Everyone is by and large at record levels of capitalization of their resource base.
When does that tail off? It’s very hard to say. And again, I showed you kind of the portfolio where things we have in front of us and it’s enormous. And none of them are going to come at a small capitalization program. They typically, they are going to be big, big multibillion dollar investments that are made over periods of time before you see the cash flow.
I think the effect of that on us and we recognize it is to take -- it’s just to reinforce the importance to us and to our people of execution that we execute the capital programs well that we manage costs well. We can do a lot about -- I mean I suppose somebody here who would want to take me on a path of hedging foreign exchange but we will do that. But it’s -- we can't offset when you have a big 4X impact on a multi-year investment in the country.
But there are a lot of other things we can manage. And you find a way to improve the anticipated economic performance of that investment by either, working cost, the technology solutions or getting more resource recovery under those same investment dollars. And when we go back and look at ours and we -- many of you are aware, we do an annual investment reappraisal.
We look at every investment we’ve made looking backwards and we evaluate how it turned out against our expectations, cost, resource, technical, commercial, all of it. And we learn a lot from that. But as we look back, what we find happens a lot of times, as we are -- as our engineers, reservoir engineers, geoscientist, developer, planners work on these things, they find -- one of the first things they try and do is get more resource under that investment dollar.
So that the efficiency of the investment dollars is improved and then that improves the overall performance. But I think it's not unique to us. We have invested enormous amount of capital otherwise I never would've dreamed we'd be spending at this level. And I think it's, what the market is responding to is that huge capitalization of this industry against the cash flow is that I think they expect. And the market has its own view of what it think is going to happen in the future as well.
What do we do about it? It’s sticking to our fundamentals. We got to be very capital efficient. We got to be very efficient with our operating costs. We got to be technically very confident and find ways to get more for every dollar we put into this thing and then operate it well, don't have problems that we said you back. Those were the things we can control.
And then keep generating that sufficient cash that hopefully, we are meeting our shareholders expectations on distributions and long-term value and security -- security around their investment.
Robert Kessler - Tudor, Pickering
Hi. It's Robert Kessler, Tudor, Pickering. When I look at your outlook, the only real forecast you presented on production growth, much appreciated. But as you caveat every year, it’s an outcome rather than a target in itself. It changes the price effects as previously mentioned asset sales and whatnot.
Meanwhile, you are managing the business for returns, return on capital employed. Your target production growth per share and you're looking to growth in cash flows. Why not present an outlook for any of those metrics?
Well, I guess expanding on which one, it starts getting into some view we have on price, which we don't like to get in to. The more granular I get, the more I’m starting to have to provide you certain price assumptions, which -- we don't have a price assumption. So, I could give you many different outlooks on it. It's the way we make our decisions, both on investments and allocation of capital and human resources. It’s across array -- as you heard me say, it’s across a range of outcomes. So to do that, we had to pick one and we prefer not to do that.
Robert Kessler - Tudor, Pickering
It’s an unrelated question, but you referenced increased investment plan in the downstream to exploit increased discounted crudes. In U.S., you mentioned logistics. You mentioned running more crude in the U.S. Can add some specificity to that, either in terms of total dollar amount or types of projects there, and how much upside flexibility do you have to run like crude in the Gulf Coast if the economics dictated as you referenced?
Okay. Let me ask, Mike to address that one. He is much more knowledgeable on the details of all of that.
As we said, we are looking at all of our assets. A lot of the investments we do are going to be aimed at more lubricant-based stocks, which also those types of products produce more diesel fuel. So those are the two growth projects. So to the degree we back that up into different crude capabilities that we need to feed those investments and you will see some changes.
We are not going to put in major investments in distillation capacity because the industry doesn't really need that. We are still in a declining market, especially here in North America and Europe. So you are not going to see that. We are always -- as we go into our returns, we are always doing the bottleneck capacity creep type projects. We are really good at that, that’s our bread and butter.
So you will see some of that. We are making investments in logistics. All the things you would think we would be doing from contracts with pipeline operators to large strategies and we have a big railcar fleet. We are always working on that. So we have a lot of things going on to help optimize the system.
In terms of -- we look at our refineries, we have very good capability as you know to run heavy crudes and there's a lot of disconnected, discounted heavy crudes as well. So not just -- we tend to focus on the light crudes but it’s not just the light crudes. If you look at our refineries across the Midwest, they are 100% today on these disconnected crudes of one kind or another. So we can find an optimal mix for the equipment we have and we feel very good about our ability to do that and continue to take advantage or whatever is out there in the marketplace.
And when you look down at the Gulf Coast, of course we were unconstrained. Today, we could run more of anything if the price was right. So we still have flexibility to move back and forth. Obviously, every piece of equipment has a constraint someday, where you can get to the point where you might have to do something. But the bottlenecks for lighter crudes are really not that, they are not that difficult in the grand scheme of engineering.
You retrace towers, your repack towers have put in more overhead cooling you make these compressors little bigger. You can get more through it. So that’s something we do really well. We have full capability on the engineering side and have still, which a lot of your competitors done so. Every time, we do a turnaround we will do some of that. So, I feel pretty good about that.
But as the logistics open up, coming down the Gulf Coast, there would be light and heavy crude avails into our big Gulf Coast refineries and we will take whatever makes sense on the day and optimize around that. We don't feel constrained. I know there's a lot of discussion about that.
We feel between -- they're still opportunities offshore we can bring on. Not every crude is priced off of a Brent. Sometime you get crudes that are distressed and cargos that are distressed. So we feel very good about the full suite of opportunities we have to get the most out of our asset. So, I think our results show that we do that as well as anybody in our business.
Thanks, Rex. I’ll (inaudible) to as well if I may. First one is, you gave us a projection on gas reduction 25% this year? Obviously that includes decline in places like Europe and so on. Can you isolate that to what you are expecting in the U.S. and if I may ask you to maybe elaborate as to where you currently stand on LNG plans in the U.S. as I’m guessing appraisal to the longer term trajectory in gas production?
Let me ask Mark to address the production question. I want to ask Andy to address U.S. LNG question.
Yeah. So in Europe, we are just continuing to see the same base decline that we’ve had for many years and then supplementing that with work program, so no real change there. In the U.S. you are seeing us move from these very dry gas plays to more liquids focus, I think that change will be more significant. Of course we can dial it up or down, on a moments notice based on how prices are going.
With respect to the LNG plans told in past specific we have the DOE permit or free trade countries we have the application in for the non-free trade areas. We are quite hard to work now in terms of the next level of permitting that has to be done speaking specifically about the permitting there and the things that stand behind that to give you the best permit possible.
I think as we try to project what the evolution of how the Q is going to work, how the market will sort things out, people that are best positioned with the strongest cases of the ones that the market are going to go forward and the market, so we had to work on that and looking forward to submitting those in the non-traditional future.
Thanks. Mark, could I appreciate just to give us a decline we expected underlying decline in the U.S.?
I couldn’t give you a specific number off the top my head.
Rex my follow up is, if I may go back to…
Actually two questions.
Well, that’s it.
Paul Sankey - Deutsche Bank
Thanks Rex. Rex, you surprised me a little bit by describing one of your slide, it’s a -- the slide that you are not satisfied with, which was the profitability per barrel?
Paul Sankey - Deutsche Bank
And you shared more granularity the volume outlook which shows that oil will grow relative to gas more quickly. On that not satisfied slide, you said plans are in place to maximize value, I assume that’s not just related to the oil gas switch. Could you talk a little bit more about how you can regain that former number one position in profit per barrel? Thanks.
Well, there are some quick and dirty things we could do, which I don't think would be necessarily wise to do yet, yet, I mean, we might conclude that we want to do that and that has to do with that mix of assets underlying. You recall in my comment, I said don’t forget the red lines on average. We got some that are way up there. We got some that are way down there.
And as part of our ongoing asset management activities, we are always looking at those underperforming assets from a profitability standpoint and evaluating those, and demand and that the organization have plans around how you are going to improve those.
And there are a lot of -- and each one of them is going to have its own set of challenges. But one, I’ll just, I’m not going to name it, but I’ll pick an example of one that’s that fairly simple is, the problem may not be with the resource, the operation or anything, the problem is with the fiscal structure. You just can't, no matter what we do, we’re never going to make anymore money per barrel. Actually it’s the nature of it.
And so you have a couple of options there, you could exit it and you'd see a loss of volume but immediate improvement in unit profitability, okay. Or you can engage with the government and say, you know, this isn’t working for us. We've got to find a way to allow us to be more profitable because I cannot continue to devote my human talent. It’s -- usually never a question of capital, I mean, we got plenty of capital availability, if we think we can generate return even on a deal that has a low unit profitability you can generate great returns. The structure will allow you to do that.
But we may, that may not be useful to us and we’ve got all -- we’ve got really talented people working on it, so we engage with the government and say, you know, there is a scope for us to talk about making this work better for us. And so you start that dialogue and that that's always an opportunity of a way you can improve that unit profitability.
So it ranges from, is it something -- in each asset it is something fundamentally about the resource and the development of that resource and the operating of that resource that we can address, we are going to go and address, is something about the commercial arrangement, we are going to go and try to address that, is it something about the fiscal arrangement, we are going to go and try to address that.
And at some point if you conclude that this is as good as its going to be then you start evaluating whether, I want to try to monetize the assets some other way and move on to the next opportunity with my people.
So that’s when I talk about those plans, that’s really what it each of those individual assets that I have mentioned on the low side of that red line, everyone of them, we’ve got the organization looking at what is it and how do we make that?
And I would then say beyond that even ones that are well above that red line, there is a lot of opportunity in some of those to add even another $0.50 a barrel by being more efficient with this or that or maybe put another lower commercial piece in plan that monetizes piece of the resource earlier then we thought we would.
So there is a lot of opportunities in that, vast array of assets we are managing to work on the nickels and dams, and in the quarters that when put against several millions of barrels of product generate lot of value.
So that’s kind of the flavor of it and I think, as I said, what’s pull that down, we are fully cognizant and knew we were going to take this shift with the two biggest, I mentioned XTO and Iraq, and both of those, hopefully you can appreciate as we try to explain them were significant strategic move for us driven by our long-term view of what's happening around the world with resources and resource opportunities.
And we can, we can show that for a period of time and still produce very good financial results, but we don’t want to show them for ever. I mean, we've got to get those improve and that’s -- but we are willing to take some time because they are such enormous -- they can be so enormously value.
We are willing to take some. Let all our processes, lot of people do what they do, ground oil at it, they’ll come a point in time where we will say, okay, this -- we just can get any better or we are happy with the progress. We see where this is going.
And that’s an ongoing thing we have and that’s why say we are not, fortunately, we are not driven to have something by eight dates certain. We’ll just kind of know when this is not the best use of our talent anymore and we’ll move that talent to something much more productive.
But there's a lot of fertile ground down there and so that’s, yeah, I’m not happy with where that position is, we are working on it. We know we’ve got to do better than that and we can do better that.
Paul Sankey - Deutsche Bank
Thanks for that Rex. Thanks for extending the -- I've got two by the way. Thanks for extending the Q&A. Thank you.
Paul Sankey - Deutsche Bank
The follow up is directly related I hope which is, could you talk a bit about your acquisition strategy currently, you did mention on extra $3 billion of spending and it seems that you are not in the mode of a mega merger or something really dramatic but more in the mode of North American incremental assets? Thank you.
Well, obviously, I’m not going to talk much about this. The -- you are correct as you watch what we’ve been doing the last couple of years ever since we put the XTO kind of critical mass piece in place and that’s what we talked about at the time. We wanted to have a critical mass piece because our expectation was, over the next few years there was a lot of things going to be out there for the taking.
And you could go about getting them an asset at a time, here an asset at a time there and trying to assimilate into our global functional structure, which I judge was going to have a great deal of difficulty assimilating that or you could get this critical mass piece and then do that.
And that was the strategic decision behind that major acquisition. All of the bolt-ons that we talk about have, that’s played out just like we wanted to, a lot of it is as you’ve seen the, I mentioned the 60,000 acreage we added in the Woodford arm very attractive acreage. No one else really could go in and pick that up because it was kind of scattered here and there. We had surrounded. So we're the logical buyer.
There were lots of people interested in having this dispersed string of acreage that was hard to ever get synergies round. But we had it already. And our trade with Denbury in the Bakken similarly, it was a great fit. They didn’t want to be in that. There are CO2 enhance recovery company.
We made a straight up swap on some properties that were really near the end of life and that’s they wanted those for CO2 enhanced recovery projects along with that we worked really elegant opportunity to provide them a long-term supply CO2 from LaBarge. So it was -- those were the kind of deals that before we couldn’t have even engage in a conversation about.
So that's today, I wouldn't call that so much the acquisition strategy as it just the continuation of our strategy around how we going to participate in this enormously important unconventionals space.
I mean we saw it, we knew what was going to do and it was how do you want to be there, and we said, want to be there in the big way. And so that’s what we’ve done in this. So the other question is our mega merger out there, something obviously I wouldn't tell you if there was, you have to read about it. Yeah.
Jason Gammel - Macquarie
Thank you. Jason Gammel with Macquarie. First question, what I believe were the two largest ExxonMobil operated projects in 2012 both experience some fairly significant cost overruns, I think PNG and Kearl, not something we normally expect out of Exxon and you did mentioned FX?
But given that both of these projects have significant further opportunity in terms of expansions. Can you talk about how you are going to be able to get costs under control this projects and what you’ve learn from this projects?
Let me make just kind of a headline comment then I’ll let Mark talk about, because he is intimately familiar with those. You mentioned the impacts of Forex and it was insignificant.
But notwithstanding the cost increases we have had, the organization has done the kind of things that I talked about, they’ve gone to work on, okay, how we’re going to get more for those dollars, given that we had to spend more dollars.
So they’ve gone to work on the resource side, say, how we are going to get more out of the dollars that we had to put into this. And that is producing the kind of results we typically are able to produce that aren’t necessarily accounted for we make the initial funding decisions. But let me let Mark speak a little more granularly about that.
Yeah. So on Kearl just again by way of background, I think, it would be remiss if I didn't command the project and if we are dealing with the 24-month delay in terms of getting modules up to Montana and Idaho to be able to manage that through resequencing and then only they start up by two or three months is really remarkable.
And as we look at the capital component of Kearl, yeah, it’s gone from $6.20 a barrel to $6.80 a barrel. But what's often overlooked is, when you look at what else it will take to operate something on the order of $25 a barrel. There is enormous opportunity there through access point.
We are really looking forward to going work on that now, because with the nature and the quality of the resource being what it is for us to produce -- for a competitor to produce a barrel of bitumen. They got to mine 1.5 times as much rock again just because of the quality of the resource.
So, yeah, the capital costs have gone from $6.20 to $6.80. But we're really looking forward to going to work on the $20, $25 on the operating cost and getting the full value of the technology we put in that eliminate the upgrade and take advantage of the resource quality. And of course, the Kearl expansion and all the debottlenecking projects, there is enormous resource still to be develop it will be highly profitable, because all the infrastructures are in place.
Papua New Guinea, just a quick update on the project. The LNG facility saw the Faroe Islands just moving on quite nicely ahead of schedule, pipeline is on schedule. We are getting ready to start some of our first list of equipment into up end of the highlands here the next month or so.
We did have some Forex exposure. We also had some pretty severe rains in the area that impacted our ability to get this pipeline up through some of these mountainous areas. And we’ve had some community issues as we work through land settlement. It’s very -- there’s hundreds of tribes in the highlands sorting out title to the land and all of that. Fortunately, we had a good process with the government. We are able to work through that.
But back to now, what we go to work on. We are looking at adding resource. We’ve already bottleneck the facility to that another 5% of capacity. Of course, commodity prices are up quite substantially from when we funded well in excess of the cost increase. But more importantly, enormous resource in the area, plenty of room on the LNG facility to had a third train, fourth train and fifth train.
So looking at what a pretty active exploration program with that, what kind of resources can we add on at very low cost to take advantage of the established footprints and that's just going to grow overtime. So really pretty excited about getting that project on in 2014 and then just active exploration add to future, the potential of our future trains.
Jason Gammel - Macquarie
Thanks for that. Now my question on the exploration program, it might just be my perception, but this would appear to be one of the more diverse and robust programs that put in forth in furnace about five years. Can talk about anything has changed from process standpoint that led to this increase? And if you could also comment on the change in spending on exploration that you are seeing over the last five year? That would be appreciated?
I think, well, that question our exploration company has sharpened its focus on its charge, which is to go out and find, discover oil and gas resources with the bill. In years past they had other responsibilities as well which I think distracted from that primary mission.
Now the geoscientists know because they hear it from me and they hear it from Mark, if you are going to live and die by the bill. And that has significantly I think refocused the organization. There have been some organizational changes internally to support that focus on that mission to become more efficient about it, to become much more nimble about evaluating emerging plays and entering those plays earlier in the process than we did in the past.
We were, I mean, in all actually we were late to somethings in the past and today our people I think are much more nimble and that’s why we’re spotting somethings now ahead. I think, if you look at the Black Sea, where we have essentially all of that Western Black Sea tied up now and we know we have discovered natural gas there. We see significant potential. It’s going to be fairly simple to develop it and it goes right into European market.
Moving all around to the northern part of the Black Sea and the strategic cooperation agreement with Rosneft, a significant resource potential there that we are on course of drilling the first well.
So I think, that's what changed I think is just a renewed emphasis, some organizational changes that remain internally to support that and a sense of urgency that we have to be more nimble. We have to -- we needed a sense of urgency and I think that’s there now in a healthy way, in a very healthy way.
And we are -- they are not satisfied yet, where they are, but they had an extraordinary year’s. I mentioned it was the largest resource addition by the bid that we’ve had since the merger. So we are starting to see the early stages of what those changes are delivering to us. And I expect more, I expect more of the same.
Jason Gammel - Macquarie
Okay. Thank you.
Ed Westlake - Credit Suisse
Thank you. Ed Westlake, it’s Credit Suisse. $38 billion is a lot of money as you said this morning but it’s still less per barrel than consumer hit because you got such good projects through to 2017. I guess, the worry might be what happens beyond 2017. How do you maintain the capital for barrel. Is it by being more assertive in shale? Is it just continuing technology and discipline, maybe some color given cost inflation, how you can manage that capital budget or little bit beyond?
Well, it really is -- it's really the resource base. I mean, you had to go back and look at what’s in the resource base, the quality of that. Because that's -- the things that we’re investing $38 billion today and that we will be investing $38 billion a year over the next few years is representative of the quality of what’s in the resource base that we can pull up, that our technologies can evaluate, get certainty around the quality of the resource. How it’s going to perform and develop that our development planners can get some certainty around the development concepts.
Often times and most of the time, a lot of these resources that are emerging that some of them have been there for while because while there is technical capability to develop them, it's not at a cost, that’s going to be attractive to us. So we have had our technologies working on alternative development concepts or technology enablement that allow us to pull those into the commercial window at a lower unit cost.
That’s what will happen if you just -- if you ask me today, okay, so let’s take a resources that’s in the 35, that’s not in the development planning stages, not pulling up today and I said how does that look on today’s capabilities. They’ll look good but the stuff we’re developing today, five, six, seven years ago, it didn't look good then.
And what’s changed is these technological advancements that get the cost down to lower a different, an alternative development concept that pulls that into the economic window. So our confidence in why we can sustain this going forward is really embedded in our past performance.
And I look at the things -- Papua New Guinea has been around long time. It’s been around long time. It is now going to be extraordinarily profitable development. But it wasn't that way 10 years ago. And when I was down in the development company as an executive VP, a lot of these resources were now developing that they were old friends of mine, that I used to ring my hands over and tell my boss, I don’t want to -- I'm not going to develop this.
I mean, you just can’t -- we can’t get it through the window. But our technologies work on that and they work on it constantly. And so that’s the confidence we have that those resources are in the resource base because we have confidence they will be commercial.
I may not be able to tell you exactly how it’s going to be commercial today but we're working on concepts and technology advancements that are going to make them commercial.
Ed Westlake - Credit Suisse
And then on follow-on, you should a great slide of Barnett drilling efficiency in North American gas. Any comment just sort of the latest progress you've made in terms of lowering the overall break-even which you got a good return in your North American gas affiliate?
Well, we showed the Barnett because it has the most well-established history by which we can share results with you with confidence. You know the nature of these type reservoirs, shale reservoirs are such that their decline curves are difficult to forecast certainly early in the stage of the play.
They all share certain characteristics but there's no type curve. There’s one thing we’ve learnt. Now, that the XTO experience in all the varied assets that that we hold in the unconventional space, there is no type curve. Every basin is going to look a little different and within the basin, it’s going to be different.
And so we took the Barnett example to show you this though as what we believe -- what we know we can do. And this is what we will replicate in the other basins. And we talked about this last year, yesteryear, what’s the long-term plan. We said we’re going to put all of our research and technology capability in understanding these better than anyone else understands them.
And we’re going to spend -- we're going to take our time early in the play to understand it. We’re going to do some appraisal. We’re going to do a lot of research, lot of analysis. And when we think we've got it figured out then we’ll put a development plan in place and ramp the rig activity.
So the Barnett example we shared with you to show -- hopefully will give you some confidence that when we say that, we can actually deliver it. And we’re starting, we’re just on the front end of what I would say really understand in the Bakken, a piece of the Bakken, not all the Bakken but a piece of the Bakken. We’ll be doing the same thing there. And we’re running 10 rigs there today as a result.
Now, we’re ready to start deploying the things we now learnt. I can say the same for Woodford Ardmore. I can say the same in any of the other plays that are at varying degrees of maturity in the play and within the play.
So, yeah, our expectation is we’re going to replicate that throughout our unconventional portfolio. It will be replicated at a pace that we understand it. And again it’s one of the strengths we have is we can -- we can take the time to do that. We can deliver it better. We can take forever but we can be deliberate about it. We don't have to generate cash out of these things right now to payroll next month.
We can go back this in a very deliberate way such that we look back on it. We’re going to have a much more profit, unit profitability out of those plays and others because of the way we were able to go back these early learnings. Yeah. Right in here in the middle. Yeah.
Evan Calio - Morgan Stanley
Yeah. Thank you. Evan Calio of Morgan Stanley. Given your considerable resource growth projects in the Q and K in the oil sands. How does Exxon adjusted that Keystone should be only viable solution, pipeline solution in that timeframe is not approved. Given your diverse footprint across North America, I mean, Israel a feasible backup plan if that doesn’t occur?
I’ll give a headline answer and then again may be let Mike come in because our supply logistics people, this is where our integration comes to bear. Our supply logistics people working with our upstream organization have been working on this for a long time.
I think headline number is there's the Canadian government is not going to sit still either. They are going to want to deal with this issue too. So all of those solutions aren’t necessarily south. And I think we all had to just keep that in mind.
In terms of our system, we’ve -- obviously we've seen the Kearl project developing from the numbers of year. So we've put a lot of thought into how we get our equity crude to market and make sure that we can always get our equity crude. So we do have plans in place, multiple opportunities on pipe as obviously Keystone to the whole system probably but that would be difficult that that didn’t come to pass.
But we do -- we have -- we have put in some new barging strategies. We have a big rail fleet. We’ve got some opportunities to handle rail all the way down to the Gulf Coast. So we've got contingency plans in place. And as Rex said sort of the Canadian government so.
We will have to see how it works out. I think we’ll be able to adjust and we’ll be as competitive as anybody. I'm sure that our guys have all the plans in place that we need to put our equity barrels here into our refineries or into the market, regardless of how these various scenarios work out.
The phase one volume, this will start-up, they’re taking care of. So this is really -- we’re really having to look at how do we want to handle the expansion phase that will start up in ‘15. If nothing happens, with Keystone, it does have an impact but as Mark said, there is alternatives. They erode some of that value because they may not be as logistically efficient. And that's what our guys are working on, how do we make them logistically efficient. So we don't have the erosion.
Evan Calio - Morgan Stanley
And my second question is on Russia, tremendous longer-term opportunities there. Could you just update us on tax policy and where that stands? Thanks.
Well, the tax legislation has been drafted. If it's not been submitted to Duma, it’s to be submitted to Duma this quarter. President Putin has maintained his commitment to send that over and have it delivered. We have been interfacing obviously with the ministry of finance, ministry of tax. So that we’re sure we're getting the language consistent with what we also said was needed to support the exploration and development of these offshore and Arctic resources as well as the unconventional.
Because they are addressing unconventional resources and at large places as well. So it’s moving along. We’ve been told that it would be submitted to the Duma this quarter. We would not anticipate any issues with its passage. But we’d like to wait, it’s not done till it’s done. Back over here.
John Herrlin - Societe Generale
Yeah. Hi. John Herrlin on Societe Generale. Rex, you mentioned in your presentation, a 4% growth liquids between 2013 and 2017. Could you break it up between light oil, bitumen and NGLs?
I know, I can. Probably evident in the book over there. But if you just think about the big pieces, obviously Kearl, they would talk about that’s $100,000 going to -- in 2015, we begin to place two start up ultimately headed to 345,000 barrels a day. So that’s about a third of it.
I don't know. I’m not sure I could tell you what NGL type is, obviously a piece of that is LNG volumes coming out of Papua New Guinea and Gorgon Jansz. Those are two big LNG projects that will be starting up in that time frame. So if that helps, I mean, about a third of its coming out of Canada in oil sands.
John Herrlin - Societe Generale
All right. That’s fine. My next question with regard to upstream portfolio, between FID and first production, your large scale projects are getting more protracted. That’s an industry phenomenon, not just Exxon situation. You’re trying to avoid or capitalize some of the short cycle stuff like the uncoventionals. Do you need more kind of mid-cycle type projects or is that really where your buybacks comes in, in terms of lumpiness upstream?
We just need good investment opportunities. There is nothing -- there is nothing strategically material to us about it being a large multibillion, say something that’s north of $3 billion, our share, long-term project versus a program in the unconventionals where you can very easily dial it up by picking up ridge or dial it down by letting it go.
We really just judged the asset opportunity on its own merit. And we don’t force the investment program towards one type of investment versus another. Each of them -- the organizations that have responsibility for those assets are charged with understanding the quality, understanding the opportunity to earn a good return and bringing those forwards when they feel the conditions are right.
And we’re not bound to say well, I’m only going to this much on conventional this year. I’m only going to do this much, heavy investment projects next. These things when they are right. And our technical people believe they are right and they are ready to be funded, we don’t bring them forward.
If there is some reason, we don't want to do them either for -- because we don’t like the government risk or we don’t like some of the other risk elements. And we tell them look let’s just hold that for a while. But it’s usually -- it's going to be some issue with these specific investment opportunity, not because it’s not fitting into some kind of mix of investment that we’re trying to achieve. Right here.
Dave Rewcastle - Source Capital Group
Okay. Dave Rewcastle, Source Capital Group. I was wondering if you would share your thoughts on GTLs stranded northern American gas, your XTO resources, your natural gas. You shouldn’t be adding value to the molecules by going to that route. I also want to know if you maybe examining some other technologies in-house or just in case, it was, I think $8 billion on some of those plants?
Well, we are -- we constantly are evaluating technical opportunities to monetize this huge North American gas resource. As you’re well aware, we have a lot of proprietary GTL technology. We have a lot -- we have agreements in place with others who have complementary technologies.
We’ve done cross licensing with others so that we would allow them to use ours and exchange and let us use theirs. So we do -- we are evaluating and I think the thing you have to keep in my mind on gas-to-liquids as a commercialization option is it is very capital intensive. The capital costs are very high.
And you destroy a lot of molecules in the process. So you’re converging efficiencies of -- I’ll start with x number of gas molecules. In the end, that will give me x number of liquid molecules in the form of either diesel or waxes products that can be converted to lubes. There is a lot of material balance lost in their process because it’s a fairly destructive process to transfer all the molecules from this to that.
So it is -- it's very much important that you have some view around -- the value of the gas molecule which I’ve now consumed a lot of to create a liquids molecule and what I think the long-term value on that’s going to be. That differential against this big investment that has to be executed and then that has to be operated very well.
And these are not simple plans to operate. But we’re looking at it, we know others are looking at it. We’re revisiting our own technology, asking ourselves questions about scale and size and is there a condo kind of size. Does that make sense? Nothing has emerged out of that at this point but I would tell you we actively look at it.
Just as we look at a broad array of ways to monetize this huge gas resource that we have and that North American now has. So that runs the gamut from GTL, gas in the transportation fuel opportunities and all the things that you're reading about and hearing about, we too are evaluating all of those.
Whether it's an opportunity in that value chain for us is a question or whether we want to promote the creation of that value chain and we’ll make all our money over here. That's also part of that whole valuation. A lot of people rush in to be part of a value chain and we some times look at it and can figure out why, because it’s kind of a utility rate of return business and we’re not too interested in that.
So, but we are looking at in and I think clearly there are a lot of options on the table for how the economy realizes the benefits of this natural gas in Duma we have. Now we go to the back, back here.
Iain Reid - Jefferies
Yeah. Iain Reid from Jefferies. A couple of questions on the Russia, Rex, if I could. Firstly, you identified obviously prospects now in the Kara to drill. Can you update us on the likelihood of oil versus gas there. And so do you think you have rights kind of regulatory framework to be able to exploit gas if its large enough on it. And the second question was on the Far East LNG, you talked about with Rosneft, is that based on the Sakhalin reserves that you already discovered or is this across additional acreage, additional work, additional drilling, et cetera to make that work?
Let me answer the Sakhalin first, because it’s fairly straightforward. The LNG scoping study that we’ve agreed to undertake would be a generic LNG plant, assuming that it would have access to a long-term supply of natural gas. So it’s really just looking at how competitive might a Russian LNG facility located in a particular place, how might that compete against all of the other LNG supply sources that are coming forward out there in the global marketplace.
So it’s a joint evaluation for them and for us as to, where does that fit into the cost of supply, seriatim for and how competitive it might be in the marketplace. The question of oil and gas in the Care, we don't know enough at this point to find on that. And whatever we find, our agreements encompass that we and Rosneft will evaluate how to commercialize those, and what kind of development would be appropriate to commercialize those in subsequent steps of the agreement.
So right now, we need to go out and drill a prospect, prove up that the hydrocarbons system extends that part of the north and we will know much more when we kind of see the results of that. But it would be far too premature to offer opinion on, what we think we are going to see there.
Paul Cheng - Barclays
Thank you. Paul Cheng, Barclays. Rex, two questions. First, last year I think the company had a concern that by trying to cause somewhat of your payout gap on dividend comparing to your peers. At this point, are you comfortable with the gap or that, you think you are still in, maybe the midpoint of the journey to further close the gap?
Well, we made a significant move to increase the dividend last year in response to what our shareholders were telling us. And in response to, as we evaluated the gap, as you call between our dividend and those of some of our major competitors. But that was opening up and so we felt, okay, we have the financial flexibility, so let’s do this. So we increased dividend 21%.
As someone commented to me earlier this morning, the share price increased instead of backward, so not a bad -- that’s not a bad problem to have. But we are evaluating again the appropriate dividend, whether we are going to have an increase. If we do how large will it be, and that’s something that the Board will discuss and so it would be inappropriate for me to say much about it, when I've not even had a conversation with my own Board about it at this point. But we are very mindful of it.
As I said, we were last year and we pay attention to it. We are not oblivious to it. And we don't have a strong bias. One way or the other, it's all driven again by that view about the sustainability of our -- how we return our cash to shareholders and with a view of what our investment requirements are going to be. So we will be looking at it, obviously again and we will have -- you kind of stay tune to see what our deliberations include.
Paul Cheng - Barclays
Thank you. The second question is that, if we look at even just using, take for an example, comparing to five years scope, the newfound opportunities in North America has been fastening. And I’m not sure that that loyalty in the mine or off the oil producing countries officials. So just curios in your, over the last 12 months in your negotiation or discussion with oil producing country official, have you seen a change in the attitude that to in the sense that to make the investment environment become more accommodating or positive for you guys? Thank you.
Well, you never want to generalize because each country have their own needs, they have their own views, they have their own budgetary requirements. They have their own political dynamic. I think, clearly, just I would say globally, around the world there is a heightened recognition of what is happening here. And I would tell you that, 12 months ago, there wasn’t. Somewhat to my surprise, a lot of the leading producing countries were unaware of what was happening here in North America with oil and unaware at how rapidly it was happening.
They are much more aware of it today. Now, how that's affecting their deliberations internally as to the development of their own resource, resources to support their economies, their social programs, the needs of their own people. It's going to be different in every country, different in every country.
I wouldn't -- I don't perceive that there's been some kind of dramatic shift by anyone to say, well, we’ve got to move from here to way over here because of this. But I think they're all watching it. I think they are trying to understand it. They surely would understand the implications for their country and where they fit in, in the global energy supply space and how they maintain their own competitiveness. I think they are mindful of that. But not many are, they are kind of going through that process I think of sorting that out still. So, I wouldn't say there has been a huge shift -- a seismic shift anywhere by anyone. There is recognition of it.
Yeah. Right here in front.
Kurt Wulff - McDep
Thank you. Kurt Wulff for McDep. I have a question about Syncrude, the project in Canada and it’s a valuable project and generating a lot of cash flow and you’ve generally had an excellent record in other projects. But this is one project that seems to be an exception in terms of meeting your expectations. It’s been about six years of having produced that design capacity yet.
And then the past 12-months have bene pretty discouraging too, with mining problems and this year with upgrader problems that we thought were solved. What do you think the outlook is for these projects? Should we still keep an eye on design capacity or should we resign ourselves that it’s just going to generate lot of cash flow at some reduced level?
Well, as you know, the Syncrude Corporation. Bill Colton operated that project for most of its history. As a owner in the project, we have from time-to-time provided them some technical expertise to help address challenges they’ve had over the years. A few years back, the owners group concluded that that operating model just wasn’t working. And it was just kind of a legacy of challenges.
And so we offer and entered into an agreement to operate under our management services agreement for them and we’ve been doing that now for the last few years. It continues to be challenged. Some of the challenges are structural just in some things that were done and decided and kind of locked in many, many years ago, that we can't do much about.
I mean physically with the facility. Some of it is still organizational, trying to get the organization performing with a culture and a level that we expect and there has been a lot of progress there. And I want to acknowledge that they’ve made a lot of progress. It's still not where any of the owners would like for it to be and so we are going to continue to work at improving the performance there.
As you pointed out, it is a valuable asset. It throws off a lot of cash, should be doing better and it will struggle to perform where we would like for it to, because there are some things that on legacy that you just -- you are going to have difficulties overcoming. And you are going to have difficulties making expenditures that correct them. So valuable asset to us though. And we go back to the back, trying to get to folks who have not had a question yet.
Faisel Khan - Citigroup
Thanks. Faisel Khan with Citigroup. Can you elaborate a little bit more on, what percentage of your upstream capital plans are going to be dedicated to the lower 48 unconventional shale -- oil and shale gas program?
When did you recall about what we are getting there for $4 billion a year. It’s about $4 billion.
Faisel Khan - Citigroup
Okay. And, can you also discuss, how XTO is performing for you as a separate business unit? How is it helping you in acquiring resource around the world, specifically outside the lower 48?
Well. First, I would take exception to characterizing it as a separate business unit because it is very -- it is now in two plus years since we’ve concluded that merger acquisition. It has become very integrated with the rest of the ExxonMobil Corporation organization, not just in the Upstream but with Downstream, the Chemicals as well.
And I think that integration has gone very well. I’m very pleased with the quality of its people and how quickly people embraced it because that was -- that’s always a question. And we've had a great harmonization between the two organizations that's been through a period where we keep throwing things on them.
We mentioned these little acquisitions we keep making. And so while they're trying to do that, we keep giving them another piece of the Marcellus, and we give them another piece of the Bakken and we give them another piece of the Woodford and we give them another piece of something else and then we tell them, by the way we are evaluating this deals called Celtic up in Canada and we need you to come up there and help us do that.
So in the midst of all of that, they have continued to integrate themselves very nicely with all of the rest of ExxonMobil Corporation, organizations. So, I'm well pleased with how that has progressed. And there -- it is very much, as we’ve described at the beginning that this was going to be a transfer of knowledge, experience and technology to win both ways.
And we showed that video at the start, obviously on purpose because what you saw on the video were heritage XTO individuals, Vice President of Exploration and others deeply embedded in our operations since the very beginning, founding of the company and ExxonMobil researchers and technologists who were heritage ExxonMobil and how the two are working very closely together.
And I think the XTO people's recognition of this enormous treasure they have available to them now by research center. And all the things that the research organization is able to do for them, but they never had anyone that could go to before. They either had to figure out themselves or they had to rely on a contractor to tell them what they thought.
So, I think that the integration of all that has been -- has occurred very well. And I would say in many respects has exceeded my expectations at this stage. They have been crucial to our screening and evaluation of many of the opportunities around the world by just looking at data that’s available and a lot of the data is pretty sparse. In some areas, there is not a lot of data. But because they’ve looked at so many examples themselves, they can spot some things where they've really been helpful is helping us rule some things out.
They may not be able to rule some things in, because that's hard to do until you go out and actually grow wells and test. But there are some characteristics that they have experienced that they can look and they say, this has got a very low probability for these reasons and we don’t waste our time on them. And so it helps us focus our pursuit efforts much more sharply in the basin that we are pursuing.
So we've been very careful and deliberate about where we have pulled on that capability because as I -- go back to what I said earlier. We have loaded their boat up with all kinds of additional North American responsibilities. We have also transferred a large number of people from the ExxonMobil production company to XTO import work, that’s helped with their assimilation into organization, developing the networks very quickly where these communications take place.
So we've been very judicial on how we pulled on them to work overseas on things. But they have helped us in various stages and then we try to let them go back and work on the really, the stuff that's important that’s going on right now. So the roles are playing out like we had hope they would.
I would say perhaps, they’ve not been -- we haven’t been able to get them as engaged overseas, that's not their fault. That’s because we keep finding really attractive stuff to keep adding to their holdings right here in North America and that’s keeping them pretty busy, assimilating that. Yeah.
Rex, obviously you don’t have enough time to go through all of ExxonMobil’s operations. But maybe you can clarify your position in Kurdistan and the thinking behind the Board and management for entry in there, given your position in Iraq and maybe discuss your drilling plans? There were reports that you are going to drill four wells, one of each -- on each of your blocks in Kurdistan this year and what sort of outlook and milestones we can look for? Thank you.
Well, I’ll make a few comments but I’m going to make many. I don’t think it’s any surprise that it’s still an issue that’s under valuation and evolving, where we want to be engaged throughout all of Iraq. And we have made that clear to the central government. We have made it clear to the regional government, when we entered into the blocks that we are committed. We are going to meet our commitments. We are going to meet our obligations. We expect them to do the same.
And with the central government, we have continued the dialog of trying to be a positive. I don’t want to use the word participate because that takes it too far, but there would be a positive party to bringing stability to all of Iraq, which is really in our interest. It’s in our business wise to have a stable Iraq, because there are enormous opportunities throughout the country. And we would like to be a part of those in the years to come. But if the country is not stable, it won’t matter we will be able to do that.
So we are trying to be a constructive, a party to hopefully stimulate the government of Iraq to address a number of outstanding issues that are important to the stability of the country over long-term. They clearly value our participation. That has been expressed to us over and over. They are very pleased with the work we've done in the West Qurna-1 concession in the south.
It has performed beyond their expectations. It is performing well to ours, limited only by some of the infrastructure needs that they have to address. They are not part of the scope of our work. And we want to continue that engagement, and we hope to expand that engagement on the right conditions in the future. So we respect and appreciate that there are different views taken within the country. There are complex issues around those views, which date back years and years and there are deep held feelings around those within the country by the various parties, many of whom -- all of whom have experienced tragedies among themselves and their people.
And we know, when we went in and we were entering a complex situation and we believe we can be successful. We know we can be successful. We hope -- we hope they will want to continue to work with us throughout the country. That's our objective and we want we want to help them. We think our being there is a positive thing for the people of Iraq. Well, that’s what we’re pursuing and I hope -- I’m hopeful we can continue to do that.
Well, listen. Let me thank all of you for being here once again, and appreciate your interest in ExxonMobil Corporation. We’ll see next year.
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