Exxon Mobil Corporation (NYSE:XOM)
Q4 2013 Earnings Conference Call
March 05, 2014 09:00 AM ET
David Rosenthal - VP of IR and Secretary
Rex Tillerson - Chairman and CEO
Mark Albers - SVP
Andrew Swiger - SVP
Mike Dolan - SVP
Douglas Terreson - ISI Group
Robert Kessler - Tudor, Pickering, Holt & Co
Paul Cheng - Barclays Capital
Doug Leggate - Bank of America-Merrill Lynch
Arjun Murti - Goldman Sachs
Evan Calio - Morgan Stanley
Edward Westlake - Credit Suisse
Asit Sen - Cowen & Company
Faisal Khan - Citigroup
Roger Read - Wells Fargo
Peter Hutton - Royal Bank of Canada
Iain Reid - Bank of Montreal
Good morning. For those of you that I’ve not met, I am David Rosenthal. I’m the Vice President of Investor Relations and Secretary for ExxonMobil and I would like to welcome everybody to ExxonMobil’s 2014 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 also 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. I would also ask everybody to please ensure that your cell phones and all mobile devices are silent at this time.
Next, I would like to draw your attention to our cautionary statement that you will find in the front of your presentation material. The statement contains information regarding today's presentation and the discussion. If you’ve not previously read the statement, I ask that you 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 today. I would now like to cover this morning’s agenda.
The first five sections of our presentation will be covered by Rex Tillerson. We will start with the financial and operating review, which includes key messages for today's meeting and our 2013 result. This will be followed by an update on our energy outlook and how it guides ExxonMobil’s strategy and our investment plan. Next we will review the systems that are used to effectively manage the variety of risk inherent in our business. We will then move to the meeting’s key thing, delivering profitable growth. Next we will show how each business is contributing to this profitable growth.
Mark Albers will review the near term upstream business outlook while Andrew Swiger will provide an overview of our unique longer term upstream opportunity set. Mike Dolan will follow with the discussion of how we are strengthening our downstream and chemical portfolio. Following Mike’s presentation, we will take a short break after which Rex will conclude our prepared remarks. Later we will conduct a question-and-answer session with the meeting ending by noon.
So, it’s now my pleasure to introduce our Chairman and CEO, Rex Tillerson.
Well, thank you, David and good morning to all of you. It is a pleasure to be with you again here in this historic venue and to be with you at the Stock Exchange on behalf of ExxonMobil, I also want to express our appreciation to the folks here at the New York Stock Exchange for allowing us to hold this meeting here now for our 12th year in a row. They are enormously helpful to us and we appreciate their ongoing support of our company as well as investors around the world. Also I want to welcome all of you who are joining us for this 2012 Analyst Meeting whether you are here in-person in this room or listening by the telephone or you are logged in to our webcast. We always look forward to this opportunity to discuss with you ExxonMobil’s investments in enterprises.
The picture you see on the photo is a picture of the coral 12th unit, nice looks very pleasant, nice sky up there, little cold today. But today I will review several topics including the key elements of our businesses that enable ExxonMobil to deliver superior long-term shareholder results. I will start with the brief overview of the key messages we hope to leave you with. First, we maintained a relentless commitment to risk management and operational excellence. Second, we expect to start up several major projects that will deliver profitable volume growth in the coming years. Third, we remain focused on improving upstream unit profitability.
Fourth, our balanced portfolio of high quality assets and our unique set of investment opportunities have positioned us well to profitably grow under a wide range of market conditions. And fifth, we continued our disciplined approach to capital allocation with rigorous project evaluation and investment selectivity while consistently returning cash to our shareholders. And finally, we plan to grow free cash flow and continue to generate long-term value for our shareholders. I’ll take a few minutes now to review our results from 2013.
In 2013, the corporation sustained solid financial and operating performance despite global economic challenges and a fair degree of uncertainty. As many of you have heard me say in previous reviews 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 in which we operate. In 2013, we continued our strong safety and environmental performance.
The application of our rigorous environmental management systems and practices resulted in improvements in store performance and in emissions reductions. We delivered earnings of $32.6 billion a return on average capital employed of 17.2% and generated cash flow from operations and asset sales of $47.6 billion. In 2013, we invested $42.5 billion in our various business lines, which also included about $4.3 billion for acquisitions. Total shareholder distributions were $25.9 billion. For the 20th consecutive year, we added more oil and natural gas reserves than we produced, with our proved reserve replacement ratio exceeding 100%.
These results reflect the strength of our integrated business model and the diligence expertise and dedication of the 75,000 men and women who work on behalf of the ExxonMobil Corporation throughout the world.
Let’s now take a look at our safety performance. ExxonMobil’s approach to business, operations and corporate citizenship is built upon a commitment to integrity and all that we do. Nowhere is that more evident than in our commitment to safe operations; with continued emphasis on both personal and process safety. As the chart shows our safety performance continues to improve and remains strong in the industry. We believe that effectively managing risk will enable us to achieve our vision that ‘Nobody Gets Hurt’. Identification and the elimination of potential high consequence of [indiscernible] those that could result in serious injuries or environmental damage enable us to effectively prioritize our efforts as we continue to improve our performance.
In 2013, ExxonMobil was awarded the Green Cross for Safety medal by the National Safety Council in recognition of our performance and our leadership in safety. Let’s take a quick look at environmental performance.
At ExxonMobil we recognized that meeting the world’s growing need for energy while managing the impacts on the environment is one of society’s great challenges. We have implemented rigorous environmental management programs that deliver ongoing improvements in our global environmental performance. The results of our actions are significant particularly in the area of energy efficiency where our worldwide refining and chemical operations have further improved energy efficiency by 10% since the year 2002.
Cogeneration of electricity in our facilities is a key enabler in our efforts to improve energy efficiency and reduce greenhouse gas emissions. Since 2009, we have increased our cogeneration capacity by about 10% and have invested more than $1 billion in cogeneration projects over the last 10 years, and that led us to self-generate over 50% of the electricity demand of our refining petrochemical and production facilities.
We also continued to progress initiatives to reduce hydrocarbon flaring, which have resulted in a further 20% decrease since 2009 bringing our efforts over the past 10 years to a total reduction of 50%. Additionally, we continue to focus on prevailing releases. For example we have reduced the number spills by over 30% since the inclusion of XTO operations in 2011. These achievements demonstrate our continued commitment to minimizing impacts to the environment while meeting the world’s growing need for energy.
Let’s now take a look at our 2013 financial metrics. ExxonMobil continues to lead our peer group with earnings of $32.6 billion in 2013. The decrease of $12.3 billion compared to 2012 largely reflects lower net gains from divestments of $8.6 billion and lower earnings in our upstream and downstream segments which is in line with the industry conditions.
Our earnings reflect the strength of our balance portfolio, investment discipline and integrated business model. And as we look to the future, we are progressing a diverse set of profitable growth opportunities. ExxonMobil’s upstream earnings per barrel were $18.3 in 2013 an average $17.26 over the last five years. Our profitability per barrel excludes non-controlling interest volumes. We believe this is a more accurate way income comparing our performance against our competitors, as both earnings and volumes are reported on a comparable basis and as we have significant non-controlling interest with Imperial Oil, while the gap has narrowed with the peer group leader, our 2013 performance was influenced by unfavorable volume and portfolio mix effects and expenses from the Kearl startup as well as early payments in our exploration activities in Russia. As I’ll discuss in more detail, one of our ongoing priorities is to improve unit profitability. This includes making strategic choices to improve our production volume mix and high grade our global portfolio. This is not an in program at ExxonMobil; it is part of a disciplined and consistent approach to continuously improve our financial performance over the long term.
This slide shows our reserves replacement performance compared to competitors over the past five years. For the 20th consecutive year we replaced more than a 100% of production. In 2013, we had improved oil and gas reserves totaling 1.6 billion oil equivalent barrels of which nearly 76% are liquids. At yearend 2013, proved reserves totaled 25.2 billion oil equivalent barrels comprised of 53% liquids and 47% natural gas. A robust diverse proved reserve base supports today’s production volumes and positions us well for new supplies in the future. In 2013, ExxonMobil’s ROCE was 17.2%, about 3.5 percentage points higher than our nearest competitor.
Over the past five years ROCE averaged 21% about 5 percentage points higher than our nearest competitor. Our industry leading ROCE performance continued through the recent period of intensive upstream capital investments necessary to help meet the world’s growing energy needs. Our sustained leadership and capital efficiency reflects our consistent, disciplined investment approach, our industry leading project execution capabilities as well as innovative technologies and our well balanced integrated portfolio. Another measure of the 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 $104 billion of free cash flow. This is more than two times the average of our competitors during a period of relatively high upstream capital intensity for the industry as a whole. Consistent, robust free cash flow provides capacity for unmatched shareholder distributions and underpins a strong financial position. So let’s take a look at shareholder distributions. ExxonMobil’s disciplined capital allocation approach preserves capacity for investments and industry leading distributions while maintaining the flexibility and capacity of our strong balance sheet for long term planning and execution.
Since the beginning of 2009, ExxonMobil has distributed $131 billion to shareholders, including $47 billion of dividends and $84 billion of share repurchases to reduce shares outstanding. During this five year period, ExxonMobil distributed to shareholders 50% of the cash flow from operations and asset sales. The payout ratio is double that of our nearest competitor over that period. In addition, we increased per share dividends by 59%. This included an 11% increase in the per share dividend in the second quarter of 2013 which marks the 31st consecutive year ExxonMobil has increased the dividend on a per share basis.
Since the time of the Exxon and Mobil merger, share repurchases have reduced shares outstanding by nearly 38% from 7 billion shares in 2000 to 4.3 billion shares at the year-end 2013. Each share of ExxonMobil owns 16% more of the production volumes today than it did in 2009. Since 2009, ExxonMobil has delivered annualized production per share growth of 4%, nearly 4 percentage points than our nearest peer. As you can see the competitor group is trending generally flat to down in per share productions over the last five years. As we’ve said for many years financial results and stock market returns particularly for a highly capital intensive industries such as ours are best viewed over a long time horizon.
An industry like ours requires sustainable risk management of cash and capital and long cycle times for investments to deliver results. ExxonMobil has generated greater shareholder returns than the broader market and greater returns than the average of our competitors over the last 10 and 20 year periods. Over the last decade, the S&P annualized return was 7% versus ExxonMobil’s annualized return of 12%. I think as most of you know ExxonMobil’s energy outlook which we refresh and update annually guides our strategic investment programs necessary to meet the world’s growing energy needs. These investments help provide the affordable energy needed to promote the economic growth as well as improve living standards around the world.
By the year 2014, the world’s population is likely to increase by about 2 billion people with also projected economic output will be up about 130% versus the year 2010. And current with these changes ExxonMobil’s 2014 outlook for energy shows that global energy demand is likely to grow by about 35%., taking into account the offsetting impacts of significant energy efficiency gains around the world. Ensuring 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 in 2010 to 2040 by energy type. Oil, gas, and coal are the most widely used fuels today providing about 80% of supplies. We do anticipate a gradual shift in the global energy mix. Oil demand will remain most prominent with about two thirds of its increase driven by expanding transportation needs.
The use of natural gas will rise by about 65% and it will become the second most widely used source of energy surpassing coal. Natural gas is increasingly recognized as a reliable, affordable and clean fuel for a wide variety of applications, and its growth was supported by advanced technologies that are unlocking abundant resources. We expect global demand for the least-carbon-intensive fuels, natural gas, nuclear and renewables will rise at faster than average rates led by power generation requirements.
Technology and energy advances have helped bring dramatic gains to standards of living, but there are still significant differences in energy used across nations reflecting various stages of their economic development. On the left, we showed demand by fuel in the developing economies of that know non-OECD countries. For these nations economic output is expected to grow by more than 250%, driving an increase in their energy demand of about 65% between now and 2040.
On the right we see a very different picture for the OECD countries. Demand is likely to remain relatively flat even as economic output increases about 80% by 2040. Over the period we will also expect to see a shift in the mix of fuels. Oil demand will gradually taper down reflecting fuel economy gains in the personal vehicle fleet. Less carbon-intensive fuel will become more prominent, with natural gas likely to grow to meet about 30% of OECD countries energy needs by the year 2040.
In total, global energy needs are likely to rise about 35% with Asia-Pacific accounting for close to 65% of this increase. We expect that oil and other liquid fuels will remain the world’s largest energy source over the next three decades, meeting about one third of energy demand while conventional crude oil production will remain the most significant source of supply; in this outlook more of the world’s demand will be met by emerging sources that are only recently becoming available in significant quantities.
You can see on the chart on the left, gains will be led by deepwater production which more than doubles through this period. We also expect to see meaningful growth from oil sands and tight oil resources with their share of liquid supplies acceding 10% by the end of the period. Natural gas liquid supply will also increase as it benefits from established techniques used to extract unconventional gas.
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, those produced from shales and other type of rock formations. About 65% of the growth in natural gas supply is expected from unconventional resources which will account for about one third of global production by the year 2040. The oil and gas outlooks make clear that there is a growing premium on unconventional capabilities along with the need to expand existing deepwater and conventional capabilities.
By 2040, we expect energy demand for the transportation sector to increase more than 40%. Despite the potential positive effects of demand growth from the downstream industry, we expect a very challenging business environment. This do reflects a global increase in the industry refining capacity, the development of alternative fuels, as well as ongoing efficiency gains. There is also the potential for expansion of new regulatory provided policies and mandates.
As shown on the chart the transportation product mix is changing. We expect the continuing shift of the transportation fuel mix toward diesel and away from gasoline. In fact we expect diesel including biodiesel will account for about 75% of the growth in liquid fuel transportation. This reflects in part high growth rates in developing countries as economic activity expands and fosters greater truck, rail and marine transportation. Natural gas will also contribute significantly to meet rising transportation needs.
On the chemical front, advancements in basic and specialty chemicals have enabled the development of versatile and lower cost materials, which replaced traditional applications of paper, glass and metal. These substitutions offer enhanced product characteristics that often bring sustainability benefits including savings in energy, water and raw material use. As we look to the future, we expect global chemical demand to grow at a faster pace with GDP as people seek higher standards of living and purchase more household and packaged goods manufactured with chemical products.
Two thirds of the chemical demand growth is expected to be in Asia-Pacific as the region acquires chemical products to manufactured goods for both domestic consumption and for export markets. In fact, China alone is expected to represent half of global demand with its rapidly growing middle class and expanding purchasing power. Other parts of the world will also have growing chemical demand but had a somewhat slower pace.
Like no other commodity, energy catches every aspect of modern life and provides tremendous benefits to people the world over. To sustain progress and further expand prosperity, the world must increase the availability of reliable an affordable energy supplies. While the scale and complexity of our energy challenge are immense, practical and economically viable options to meet peoples’ energy needs are continuing to expand all of these solutions should be pursued.
Access to high quality resources remains critical and it is our ability to develop supplies in ways that are secure, and environmentally responsible that will enable that. In this regard, technology advances are a key enabler to both safe and effective development of traditional and emerging energy sources such as we’ve recently seen both with shale gas and tight oil. Substantial investments are and will be required to meet growing demand including the development and use of advanced technologies that are expanding and diversifying the sources of energy supplies.
Free markets supported by sound and reliable public policies remain vital to future energy developments. This includes policies that promote and open trade which encourage private sector investments by reducing uncertainty. And overtime our industry must effectively plan, develop and execute the technologically complex and capital intensive projects that provide the energy that people need.
Next I’m going to cover key elements of our corporate strategy that are common to all of our business lines. Successful implementation of this strategy is essential to our delivering on our commitment for profitable growth. An example of this success is shown by the photo of modern LNG cargo vessels departing Qatar at [indiscernible] to supply the world’s need for reliable and affordable energy.
ExxonMobil’s strategy has been adopted to achieve our commitment to create long term shareholder value. Key elements are shown for you on this slide. As discussed earlier our relentless attention to operational excellence supports safe, reliable and efficient operations. Our diversified balanced portfolio is a fundamental competitive advantage. Resource and geographic diversity across the portfolio enable us to manage risk in a dynamic market and a geopolitical environment and to maximize profitability as changes occur in both of those. As we continue to realize the benefits of our integrated model, the complementary strengths of each of our businesses allow us to maximize the value of the molecules we produce. Whether we refine it or we manufacture in the something of higher value.
Our integration and global perspective enable us to select, pursue and advance the most attractive business projects. We are committed to continuing innovation in the pursuit of technology leadership across all of our business segments. And at the very heart of our success is the talented men and women or ExxonMobil and their drive to achieve premier business results. We must continue to attract, retain and develop this outstanding talent. Our long term approach to managing the company has positioned each of our businesses to be at the top of their respective areas of competition, enabling the delivery of superior returns to shareholders.
We know from experience that the pathway to achieving positive results for all stakeholders is to effectively manage the risk that are inherent to our business. So I do want to take a minute to remind you of our approach. Risk management is at the core of our business and there is an element of risk in virtually everything we do. Therefore it is incumbent on each and every one of our associates to recognize the elements of risk in their jobs to understand and asses that risk and to effectively mitigate or eliminate significant risk. We take a systematic approach to risk management, guided by comprehensive system known as the operations integrity management system or in short OIMS. OIMS provides a risk management framework with rigorously applied systems and processes to manage safety, security, health and environmental risk and to achieve excellence in our operational performance. OIMS guides the activities of each of our employees as well as our third-part contractors around the world. It has become embedded into work process at all levels, so everyone is expected to operate the same safe way every day, everywhere around the world.
Through OIMS, we focus on clearly defined policies to reinforce accountability and leadership and reset expectations, measure performance and recognize progress. Bottom line, OIMS helps us to sustain superior operational performance, achieve continuous improvement and ultimately to maintain our license to operate. We leverage our proven systems to enable us to first and foremost prevent incidents but in the event an incident occurs to also be well prepared to respond rapidly and effectively. Through a comprehensive set of risk assessment protocols, we focus on identifying assessing and mitigating risk. We apply sound design standards and implement rigorous procedures for the safe construction, proper operation, regular inspection and maintenance of our assets.
A similar approach is applied to our information technology systems in the safe guarding of our proprietary information. We also utilize state-of-the-art process control systems in our operating facilities. And what we endeavor to prevent incidents, we consistently apply comprehensive and fully integrated incident command and coordination approaches to emergency preparedness and response. A key factor in preparedness is to continuously train and test resources and plans to ensure our readiness to respond. In summary, our approach to risk management is supported by well-developed and clearly defined policies and procedures to ensure that we have a structured, globally consistent system with the high standards in place.
What a great picture, that’s one of our Bakken rigs operating up in North Dakota. So, next I am going to review the key elements of our strategy which will enable ExxonMobil to deliver profitable growth and provide superior shareholder returns. Strong cash flow provides the financial flexibility required to fund our business and generate robust shareholder returns. This chart summarizes key elements of our strategy that drive cash flow growth. In the upstream, we are adding new production volumes through major project startups. We are improving the production mix with higher liquids and liquids linked volumes. And we are increasing unit profitability through improved fiscal terms and reduced production of low margin barrels.
In the downstream and chemical segments, we are diversifying feedstocks through our flexible and integrated system continuously pursuing operating efficiencies and maximizing sales of higher margin lubes, diesel and chemical products. Cash flow has also provided from an active and ongoing portfolio management program and our CapEx discipline. Underlying all of this is operational excellence, our integration advantages and technology leadership. These all support our ability to grow cash flow. I will provide more insights into each of these key elements of cash flow in the charts to follow.
The first key enabler is the increased production for major project startups through the year 2017. We anticipate adding about 1 million net oil equivalent barrels per day over the period in line with the outlook from last year’s Analyst Meeting. More than one-fourth of our production volume target is expected to come from projects that have already started up such as Kearl and we will be achieving their capacity levels over the next several months. As indicated we plant to startup a significant number of major projects over the next couple of years. Papua New Guinea LNG, Arkutun-Dagi and our Cold Lake Nabiye expansion projects will start in the coming months of 2014. While Banyu Urip, the expansion or next phase of the Kearl project, Gorgon and Upper Zakum expansion will add significant volumes growth in 2015.
We anticipate first production from Julia and Hebron in 2016 and 2017 respectively. These projects exemplify our focus on maintaining a diversified portfolio weighted toward liquids volumes, highlighting our ability to grow profitable volumes. This chart depicts our production volume outlook from 2013 to 2017. The dotted line is what we showed you last year and the solid line is our updated outlook. The gray shading illustrates the reduced volumes from deliberate strategic choices we made this past year to improve our unit profitability and maintain a selective disciplined capital allocation. These strategic choices include reducing exposure to low margin barrels, such as those from Abu Dhabi onshore concession. And significantly reducing capital spending for North American gas, while increasing our North American liquids production. The remaining difference is primarily due to changes in project timing assumptions, mainly reflecting the Kashagan pipeline issue in Kazakhstan and delayed startup of Gorgon in Australia and Hadrian North in the Gulf of Mexico.
We also progressed improved fiscal terms from the West Qurna 1 concession in Iraq and the Upper Zakum in Abu Dhabi. We anticipate total net production to grow from 4 million to 4.3 million oil equivalent barrels per day from 2013 to 2017 adjusted for the Abu Dhabi onshore concessions and the West Qurna 1 effects. While this outlook reflects our current views on the market demand for North American gas, as I am sure you know we have a deep ready to drill inventory locations and the ability to quickly increase production to meet a fundamental change in demand.
The choices we made reflect a balance between measured profitable volume growth capital spending.
Now let’s look at production volume mix which is another enabler of profitable growth. This chart shows the liquids and gas detail of our total net production outlook through 2017. We anticipate total volumes to be flat in 2014 and grow about 2% to 3% per year in 2015 to 2017. Note that our projections are based on the 2013 average Brent price of $109 per barrel. The actual production in any specific year can vary due to factors such as price, quotas, divestments, weather, regulatory changes, geopolitics, unplanned downtime and project timing, whether in our operations or properties that are operated by others.
As shown by the green line, the majority of our total production increase comes from liquids, with a growth rate of 2% in 2014 and 4% per year in 2015 to 2017. As shown by the red line gas to be down 2% in 2014 reflecting reduced North American gas volumes and lower European demand. Despite continued North America gas decline over the period, we then expect gas to be up and average 1% per year through 2017 primarily driven by higher margin Ladies and gentlemen projects coming on-stream.
And as I mentioned earlier we do have the ability to quickly respond to market condition changes in North American gas demand. Overall higher margin liquids and liquids laid gas volumes are projected to account for 69% of our total production by 2017, improving our total portfolio of profitability mix.
Next I’d to review our investment plan. ExxonMobil invested in attracting opportunities to the normal ups and downs of the business cycles. Projects are evaluated under a wide range of possible business and economic conditions and we expect them to deliver competitive returns through aspects of the business cycle, 2003 was a record year for capital spending. Excluding acquisitions of $4.3 billion full year CapEx was in line with our plan.
Going forward, we expect to invest just under $40 billion in 2014 in an average less than $37 billion per year from 2015 to ‘17 excluding potential acquisitions. The plan reflects lower upstream spending and marginally higher spending in the downstream in chemical on projects with attractive returns. While maintaining financial flexibility to pursuit potential strategic opportunities, we remain disciplined in selective with our capital and focused on ensuring that any new investment contributes to robust cash flow growth.
ExxonMobil has delivered strong free cash flow over the last five years as illustrated on this chart. The year 2013 marked an inflection point after period of intense capital spending in our upstream business.
Now as major projects ramp up and production volumes grow profitability mix improves and CapEx rolls over, we expect material free cash flow growth through 2017 at constant 2013 prices. Continued strong contributions from our downstream and chemical businesses along with selective investments to strengthen the portfolio will also contribute to free cash flow growth. Our commitment to growing free cash flow underpins our ability to deliver continued superior long term total returns to our shareholders.
I’m now going to hand the program over to Mark who will review the elements of our near term upstream production growth. Mark?
Thank you, Rex and good morning. So as Rex indicated out pull back to ending a little now we’ll look in more detail at the projects behind our growth up to 2017, and I’ll also give you a little more feel for the relative profitability of these projects. So, let’s start with the project inventory on this next chart. We do have a very large high quality project inventory totaling about 24 billion oil equivalent barrels. We’re pursuing more than 120 projects the 21 projects sided to start up by 2017. These projects provide very good exposure to very broad range of resource types and as you can see on the last attractive fiscal regimes.
This is going to be a big year. We will start up a record 10 major projects adding about 300,000 oil equivalent barrels. And eight of these 10 projects are liquids linked. We are well positioned for high margin low risk liquids growth in North America with an industry leading leasehold position. Our unconventional position totals more than 10 million acres including high quality tight oil and liquids rich plays in the Bakken, the Permian, the Woodford Ardmore, the Montney, Duverney, the Athabasca Oil Sands and high quality shale gas positions in the Marcellus and Haynesville. In addition of that we have another 10 million acres of conventional resource that will contribute to the long term liquids production.
The combination of XTO’s execution capability and ExxonMobil’s research capability is making a difference. Execution of fast drill and propitiatory convention technologies alone have yielded 15% to 20% lower cost already and those are growing. As shown in the lower left we’re growing profitable liquids production to 1 million barrels per day by 2017, representing about 50% increase since 2012. And you can see the gas outlook by the red line on the left and as Rex mentioned we have plenty of capacity and capability to respond to changes in the market.
Shown in the upper left we’ve increased the number of rigs in the oil and liquids rich plays and simultaneously reduced the gas rig count since 2010. Liquids rich drilling now accounts for about 85% of all of our operated rigs. The bottom chart reflects the choices we’ve made to grow production volume in the three highest margin plays; the Bakken, the Permian and the Woodford Ardmore. Net liquids production will increase from 85,000 barrels per day in 2010 to 225,000 by 2017. And going forward the earnings yield per barrel for these plays is on the order of about 40% higher than we have today.
In the Woodford shale play and the Ardmore and Marietta Basins we grew production by more than 70% in 2013 the mixture of pad development delineation drilling. Going forward volumes will increase on average about 36% per year between now and 2017. We continue to see good success in delineating both the Kenai reservoir and the Marietta area south of our core Ardmore area. For example, our initial Marietta Woodford well tested almost 1,000 oil equivalent barrels per day, 70% of which is crude and condensate.
In the Permian Basin we have 1.5 million acres of legacy leasehold positions. We produced more than 90,000 net barrels of oil equivalent daily production in 2013 roughly 80% of which was liquids. This year we’re going to increase the operated rig count to 10 or 11 rigs by year end. We’re also expanding our unconventional production embarking on a multiyear horizontal drilling program in the Wolfcamp. We recently closed a strategic bolt-on acquisition that added 34,000 acres of high quality acreage right in the heart of the play.
Let’s look in more detail in the Bakken on this next chart. The growth engine of our U.S. liquids production is indeed the Bakken tight oil play where we’ve built a very high quality 570,000 acre position. Since XTO entered the play in 2008 operator production has increased more than fivefold and our net resources approaching 1 billion oil equivalent barrels. Last year we increased production by 81%. We recently acquired a 190,000 acres through a bolt on acquisition that allows us to deepen the high quality drilling inventory that we already have and seamlessly integrate this inventory with the properties that we have in hand. We’re now completing most of our tight based wells in the sweet spots and then significantly increase the number of frac stages between 30 and 40 in fact recently we’ve gone up to 43.
As you can on the see on the lower left, we’ve achieved an almost 60% increase in initial seven day production rates over the past two years. We continue to increase the high margin yield here through cost reductions; we’ve reduced drilling days by 28% and have captured a 39% reduction in per stage fracing costs. These achievements have contributed to a 25% decline in total drilling and completion costs in the past two years. XTO and our research company continue to work together to improve near term results of increased recovery and reduced cost. Example of this is the next generation of our completion technology we call X-frac. This proprietary technology eliminates the need for multiple [indiscernible] that are normally required for hydraulic fracturing enabling completion at much lower cost and accelerated production compared to industry’s current approach.
With that background let’s now move to the Athabasca oil sands. Kearl project initiated production last year tapping a top tier 4.6 billion barrel resource that’s going up about 40 years plus of plateau production. [indiscernible] were initiated in the third quarter using Kearl’s innovative froth treatment technology to deliver pipeline quality crude without the need for a costly upgrader and with the greenhouse gas footprint on par with the average barrel of crude oil refined in the United States. Production ramp up continued through last year and has been steadily increasing towards full design capacity through this winter. The Kearl expansion project remains on budget and on schedule. Project is realizing the benefits from a ‘design one, build multiple’ approach and incorporates existing infrastructure as well as lessons learnt from initial development phase. The project is 75% complete. It will double Kearl’s production to 220,000 barrels per day for the next four to five decades. Start-up is planned by the fourth quarter of next year.
Additional de-bottlenecking activities are currently being assessed and they’re going to increase production to 345,000 barrels a day again for multiple decades. The oil sands provide a wonderful opportunity to leverage our integrated supply chain and technology set to maximize the value from this asset. ExxonMobil and Imperial Oil are using improved subsurface imaging, stratigraphic analysis and applied learnings from similar deposits in the region, they really steer the mining operations to the highest quality ore. This will not only enhance mine planning but also operational efficiency, with targeted savings of several hundred million dollars, this technology both increases margins and volume uplift. ExxonMobil has access to the majority of the heavy crude conversion capacity in North America; we’re taking advantage of our integration and commercial expertise to secure attractive solutions to deliver broad market access for the Kearl bitumen. We recently announced the Edmonton rail terminal, a 50-50 joint venture between Imperial Oil and Kinder Morgan, Canada. This project will ultimately provide up to 250,000 barrels a day of oil transportation capacity enabling flexible supply of bitumen crude to a refining network and third parties. Between increased rail capacity and already committed pipeline capacity we now have more than sufficient capacity to efficiently move not only current but upcoming production to the highest margin locations.
Let’s now move to a conventional resource development. The Upper Zakum field is one of the world’s largest oil fields with the resource estimate of 50 billion gross barrels. In association with our joint venture partners we’re applying leading edge regular modeling, and extended reach drilling technologies that will increase production capacity to 750,000 barrels per day in the next three to four years. We recently secured improved fiscal terms that will support future investment and strengthen our long term partnership. In Indonesia, the Banyu Urip project will develop 450 million barrels of oil to an onshore central processing facility with a 165,000 barrels per day production capacity. They recently completed a number of upgrades to the early production facility which will allow production capacity to reach 30,000 barrels per day currently. Full through start-up is expected around year-end. Earnings for barrel yield here will be accreted to our overall global average in 2013.
In Iraq the ExxonMobil led redevelopment effort has more than doubled West Qurna production capacity to around 500,000 barrels per day. We continue to drill additional wells, debottleneck facilities and add water injection capacity to provide reservoir and pressure support. We recently negotiated the last fiscal terms, bringing earnings per barrel a year closer to our overall global average. This meets our criteria for future investment and will contribute to our Iraq’s plans to boost production.
In the deepwater we have a strong inventory of high-quality opportunities in various stages of maturities. We are capturing near-term benefits, leveraging existing infrastructure and maximizing profitability of our foundation projects. The examples include Kizomba Satellites Phase 2, 85,000 barrels a day tie-back to the Kizomba-B FPSO, that will develop close to 200 million barrels of oil. And that’s to get started up -- the startup is expected in 2015.
Nigeria, we’re developing the second phase of tie-backs to the Erha FPSO providing another 16,000 barrels per day of production. We expect to start drilling the first of seven wells this year with production start-up by 2016.
We’re also pursuing the development opportunities in the Gulf of Mexico. Hadrian South, of subsea tie-back to the Lucius Spar will startup this year. We’ll also begin drilling the first phase of the Julia project later this summer. And Julia is a six well tie-back to the Jack/St. Malo facility. Julia has an in-place estimate of 6 billion barrels of oil. And performance of the first phase will help guide us on the ultimate development plan.
The seven projects that are shown there in green will also on average yield to earnings per barrel above our 2013 global average. Development planning is underway for the projects that are shown in yellow. And these projects will also deliver and earnings per barrel yield in excess of our 2013 average. Attractive deepwater exploration potential is shown in red which Andy will speak to shortly.
The successful execution of the PNG LNG project has allowed us to unlock the potential of this high-quality 9 TCF resource. I have to tell you we bought all of our execution capability to bear here beginning with the construction of the 434 mile pipeline, and as you can see in the bottom left, that begins the LNG plant near Port Moresby, goes up through mountainous jungles to the gas plant at about 6000 foot elevation and then up to the well pad at around 9000 foot elevation.
Installation was accomplished here while overcoming flooding, volcanic soil conditions, and steep pinnacle reef slopes. Pipes had to be airlifted by helicopter, as the soil cannot support heavy machinery or the transportation loads of trucks. This was no easy task, as we were talking about enough steel to build 20 Eiffel Towers. Because of the lack of pre-existing infrastructure we built supplemental roads, communication lines and a new airfield that was cut into the side of the mountain. This enabled us to accommodate an antenna of 124 which was able to airlift many of the large modules for the gas plant and the drilling activities. The project required substantial outreach, engagement and effective relationships with the governments and indigenous communities.
Despite the many challenges the project is actually progressing a few months ahead of schedule, the first cargo delivery in the middle of this year. This project is ideally located to supply traditional long-term sales to customers in Japan, China and Taiwan. The PNG LNG project provides as well and accretive earnings per barrel yield and we continue to look at expansion opportunities for a third accounting, and then space for fourth and fifth.
In the Arctic we’re building on more than 90 years of experience with our Arkutun-Dagi, the next phase of the Sakhalin-1 development in the Russian Far East. This project is the largest offshore oil and gas facility in Russia. It will develop 630 million barrels of oil with 90,000 barrels per day of production capacity. The submersible topsides will be set on the gravity-based structure. Plans are to startup later this year with the first full year of production in 2015.
The Hebron project in eastern Canada is another major Arctic development. Hebron is expected to recover more than 700 million barrels of oil with 150,000 barrels per day at peak capacity. The picture shows construction of the gravity-based structure in Newfoundland which should be floated to a nearby deepwater site this summer to complete the construction activities. Fabrication and the platform tops just started last year and the first production is planned in 2017.
We are also developing the Hibernia South extension project in Eastern Canada at a subsea tieback that exist in Hibernia platform. Project is expected to develop a 170 million barrels of oil and then 55,000 barrels a day of production capacity. Along with the other expansions at the Hibernia hosting we’ll extend the producing life and help to double the field’s estimated ultimate recoverable. Startup is expected next year, next quarter, sorry. These three projects will all yield accretive earnings per barrel of production and continue ExxonMobil’s decade long legacy of developing complex harsh environment project developments.
Before concluding this section let me show with you what we’re doing to maximize the value of installed capacity which is often the lowest cost barrel to go after. Over the past five years we’ve achieved close to 25% less downtime than our comparable side by side assets in which we have a non-operating interest. Operating in harsh environments and climates is no exception. In Sakhalinsk where harsh weather and dynamic ice cover are ongoing challenges uptime has consistently been around 95% start up since 2005. These results complement relentless focus on operational integrity and facility reliability.
As with reliability have disciplined focus on cost management is core to our operating culture. As shown on the chart which is based on each companies’ last reported 10-K and 20-F data, we delivered production at the lowest unit cost relative to peers in 2012. We also use industry leading technologies to improve hydrocarbon recovery from existing fields. As an example extended rich drilling technology has allowed us to access remote reservoirs that otherwise would be left un-drained. 26 of industry’s 30 longest reach wells have been drilled by ExxonMobil including last year’s record at Chayvo, which was drilled horizontally almost 8 miles.
So I want to leave you with two key messages the first is major projects will deliver 1 million oil equivalent barrels per day production by 2017. And second, we are focused on adding production that increases the margin of what we’ve got coming on relative to what we’ve already got today. We’ll deliver that production by choosing the very best projects on a very deep diverse portfolio by bringing superior execution capabilities to bear and negotiating fiscal terms and delivering industry leading technologies and cost management.
Thank you for your attention. I’ll now turn it over to Andy who will show our long term opportunity set.
Thank you, Mark. We’ll now look a little bit longer further out. Our strategies are designed to deliver long term gain. These strategies have stood the test of time as we faced ongoing challenges in 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 of geographies.
Now I’d like to focus on our long term opportunity set, which continues to differentiate us from competition. To discuss our long term opportunities it is best to start with our superior resource base. During the past year we added almost 7 billion barrels to this resource base. After accounting full production, provisions and deletions, the total resource base grew by almost 4 billion barrels to nearly 91 billion barrels. The portfolio remains evenly split between conventional and unconventional resources and between liquids and gas. Compared to last year barrels on the proved remain about the same or slightly replaced production.
Design and development barrels grew by about 1 billion. Those we’re evaluating for future projects grew by about 2 billion. This year’s increase is essentially driven by opportunities being evaluated for future developments including Upper Zakum in Abu Dhabi, Tanzanian LNG and Western Canadian Oil Sands taking closer look at future opportunities. As you can see from this map, we have a deep and diverse portfolio of exploration opportunities around the world. In total we hold more than 61 million in net acres from under explored regions with high risk high reward potential toward establish lower risk basins close to existing infrastructure.
Green colored dots highlight conventional opportunities. These include activities in established areas such Nigeria, Papua New Guinea, the Gulf of Mexico and Tanzania as well as new areas where we have made significant additions to our conventional portfolio including Brazil, Liberia, Gabon and South Africa. Red dots highlight our unconventional portfolio. During the past year, we added new opportunities in tight and heavy oil in Canada with our Celtic and Athabasca Clyden acquisitions. We also have significant activity in South America and Western Siberia. Our Arctic portfolio is shown in blue dots. The Arctic segment is our most recent and most substantial addition to the global portfolio. Simply put when considering all these long-term opportunities we are well positioned to leverage the depth and breadth of our worldwide experience as explorers, developers, producers and technology innovators.
Now we look closely at some strategic decisions. In Russia for instance we have significant activity levels in the highly perspective Arctic basins and in West Siberia. Last year we expanded our strategic cooperation agreement with Rosneft to include seven high Arctic licenses. With this new acreage, we work with Rosneft to explore almost 190 million acres, an area stretching almost halfway across the Arctic shoreline and covering nine time zones. The Arctic area holds some of the last large untested basins in the world. We believe there is potential for multibillion barrel working hydrocarbon systems here.
Data collection including 2D and 3D seismic in the Kara Sea to evaluate and build a robust prospect inventory is underway, and has been for some time. This allows for optionality as the partners move to drilling operations in the coming years. We have begun Ice and Metocean studies to better understand the technology needed to effectively explore the high order [ph]. The Kara Sea is an extension of the prolific West Siberia basin on for many of Russia’s largest oil and gas fields. Later this summer, we plan to drill the first well in this area on a multibillion barrel university prospect. This is just one of several prospects in the Kara Sea.
Our opportunities in Russia also include a tight oil pilot development project in West Siberia. Our joint venture with Rosneft will cover an area which is within an established conventional producing area with significant tight oil potential. Last year’s activity included a mix of workovers, production and extrapolation (Ph) well deepenings as well as vertical well drilling. We are focusing on some 20 blocks in the Bazhenov and 17 blocks for the Achimov where the joint venture will leverage XTO expertise and technology to maximize recovery from each well. The team is currently finalizing drilling plans for the first Bazhenov horizontal wells which are set to begin later this year.
Moving further south to the Black Sea; we have a strong position in an emerging new hydrocarbon province covering some 9 million gross acres. The areas shown by the yellow outlines on the map. In the Romanian part of the Black Sea we will initiate appraisal drilling on the multitrillion cubic foot Domino discovery later this year. This is a highly perspective area with multiple plays and follow on potential. The Domino discovery de-risk several prospects in the area which will result in further exploration drilling plan for late 2014. Earlier this year an ExxonMobil consortium was awarded the deepwater portion of the adjacent media license covering 125,000 acres using 3D seismic acquired in 2013 we will be maturing exploration prospects for drilling in 2015 onwards.
In the Ukraine, we maintain our interest in the Skifska license but are on hold due to current circumstances. In the Tuapsinskiy block in the Russian Black Sea we acquired seismic data last year and are currently processing the survey. There are active natural oil seeps on the block indicating a working hydrocarbon system. Structure on the seismic show multiple stacked reservoirs. The block has high potential and we plan to spud our first exploration well with Rosneft late this year or early 2015. The Kurdistan region of Iraq is home for several giant oilfields improving Kirkuk and Shaikan. And much of the region has been underexplored until recently.
Some of the most prospective areas are simple add clients (Ph) expressed as present day surface highs. We are progressing efforts on six blocks covering almost 850,000 acres. We began seismic acquisition last year and drilling operations are currently underway with two rigs. These are relatively long duration wells thus results are expected later this year.
Now I expand a little bit on March earlier overview of unconventional activities in the United States and how we’re further leveraging XTO’s capabilities internationally. Starting with Argentina we have an active program underway to evaluate nearly 850,000 net acres in the high potential Vaca Muerta shale gas oil and play -- shale gas and oil play.
Today, we’ve participated in seven wells within the highly perspective Neuquen basin, with ongoing drilling and testing to identify the broad outline and sweet spots and to validate resource recovery potential in support of future development decisions. We’re currently drilling our second operated well. Additional wells are planned for the rest of this year to continue to delineate the play.
In Columbia we’re progressing efforts on our four blocks within the Magdalena Basin. Operations are underway on the Mono Arana 1 well to complete and test liquids potential for the La Luna Formation, which is the hydrocarbon source rock for the giant fields across Columbia and Venezuela. The plan is to drill a second well in 2014 together with shooting seismic. In Canada, we continue to expand our strong unconventional portfolio. In 2013 we completed acquisition of the high quality Clyden heavy oil leases.
This in situ heavy oil acreage complements our offsetting quarter leases and strengthens our position within the Athabasca heavy oil region of Alberta. In addition we established a significant position in the sort of type of liquids plays through our acquisition of Celtic Resources Limited. This acquisition added more than 600,000 net acres within the liquids rich Montney and Duvernay shale plays. XTO is currently using their capabilities and technology to convert this acquisition into near term production volumes for the six rig program during this drilling season.
ExxonMobil had an exciting year; in 2013 we entered three new countries and discovered new resources on existing acreage. Along with prolific West African coast we acquired an 83% interest and operatorship in Liberia block number 13. We also acquired a 30% in the Arouwe Block offshore Gabon, where well is planned for this year. In South Africa, we acquired a 75% interest in the offshore Tugela South Exploration Right, an area comprising over 2 million net acres.
In addition to initiating exploration activity in these new countries we have resumed activities in Madagascar after a period of suspension resulting from political uncertainty. Geological studies and evaluation are underway for three deepwater licenses or seismic data has confirmed the presence of several attractive prospects and leads.
We continue to achieve drilling success in Nigeria and Tanzania. In Nigeria, we discovered additional resources in our existing fields, including the Edop discovery near our Idoho field. We continue to evaluate the commercial development of these resources and the additional prospectivity in the areas. Our acreage in Nigeria includes an extensive inventory of prospects and leads and we’ll be testing some of these with Wild Cat drilling in this coming year.
In Tanzania, we continued to maintain 100% exploration success rate, whereas Tangawasi and Lavani discoveries bring the total resource size up to 17 to 23 cubic feet in place. Both wells discovered resource in new reservoirs intervals that had not been previously tested on the block.
Development planning is underway for the foundation LNG project and additional Wild Cat drilling is planned in 2014 and 2015. Our growing number of new opportunities in Africa gives us exciting new choices for future project developments.
Our global portfolio is well positioned to capitalize on a growing demand for LNG; the ExxonMobil energy outlook sees global LNG demand more than doubling by the year 2025. We’re evaluating several potential new opportunities to supply this growing demand. ExxonMobil has been a leading player in the development of the LNG industry where our existing equity interest and approximately 64 million tons per annum of operating capacity in Qatar and Indonesia.
Through these ventures we have accomplished a number of industry firsts, including our successful commissioning of the largest LNG trains establishing integrated LNG value chains in the European and U.S. markets and developing LNG markets in Asia and around the globe. We also have interest in 22 million tons per annum of new LNG capacity under construction through our participation in the Papua New Guinea and Gorgon projects. We’re capitalizing on a world class experience, technological capabilities and our LNG marketing expertise as we progress a number of exciting new opportunities to grow our LNG portfolio as shown in the red dots.
Following our exploration success in Tanzania we’re currently in the development planning phase including undertaking onshore site selection and commercial discussions regarding our potential joint LNG plant with the joining blocks. In Australia, development and execution planning continues for the Statoil LNG project following the receipt of environmental approval. Floating LNG is being progressed as the lead development concept and early engineering activities are underway. In Sakhalin in Russia, we are looking at a potential Far East LNG project in partnership with Rosneft. Although the new opportunities are focused in North America, which I would like to review in more detail on the following chart. Based on our energy outlook, North America’s role as a LNG exporter is set to expand significantly to represent approximately 15% of the global market for the 2025.
This will be supported by continued development of abundant local supplies in North America where we have an industry leading portfolio of high quality assets. Against this industry backdrop, we are progressing three LNG opportunities in North America, Golden Pass in Texas and potential projects in Western Canada and Alaska. At Golden Pass, we are looking to add 15.6 million tons of export capability through the existing import in a joint venture with Qatar Petroleum. We received authorization to export LNG to free traded countries and are awaiting authorization for export to non free trade countries. We have begun the FERC pre-filing and in review process as well as awarded pre-feed contracts for both the pipeline and terminal aspects of the project.
In Western Canada together with Imperial Oil, we are developing plans for proposed LNG facility. Last year we received approval from the National Energy Board to export up to 30 million tons of LNG per year for 25 years subject to final Federal Cabinet approval. Next steps include finalizing plans for the site and defining the project concept. Finally in Alaska, we are looking to develop an LNG project to commercialize the North Slope gas resources. The project concept includes a gas treatment facility on the North Slope, an 800 mile pipeline and a LNG plant in the Nikiski industrial area in Kenai, Peninsula. The partner has recently signed a heads of agreement advancing the fiscal framework including State of Alaska participation in the project. Overall, we are pursuing attractive opportunities to match abundant North American gas supply with LNG export capability to meet rapidly growing global demand for natural gas.
In summary, ExxonMobil has a long track record of success in finding and developing a broad spectrum of resource types. We have a large diverse portfolio of opportunities to choose from and our superior resource base and large new opportunity set. Resource and geographic diversity supports our risk management approach. We are not overly reliant on any single project. Our rigorous portfolio evaluation and prioritization enable project selectivity to advance only the most attractive opportunities. ExxonMobil is well positioned for long-term profitable growth in the upstream business.
Well, thank you Andy and good morning everyone. During the next 15 minutes, I will provide an overview of our efforts to strengthen our premier downstream and chemical portfolio. At last year’s meeting I presented an in-depth look at our downstream and chemical businesses. We are very proud of these businesses that deliver industry leading returns through the business cycle. We are the largest global refiner, a premium marketer of fuels and lubes. The largest manufacturer of lubricant basestocks and one of the largest chemical companies in the world and we are the most profitable downstream and chemical business in our industry. Underpinning our success are the ExxonMobil corporate values and constancy of purpose as well as three distinguishing characteristics.
First is operational excellence which includes safety and environmental performance, reliability and asset utilization. ExxonMobil strives to be best-in-class in each of these areas. The flexibility of our integrated sites enables us to rapidly capitalize on changes in the market. Proprietary technology enable optimization in real-time and the development of new high valued products. The second distinguishing feature is our industry leading portfolio which is the best overall collection of brand and assets in our industry. We have a disciplined approach to managing our asset and we have a healthy pipeline of attractive projects which I’ll discuss in more detail today. The third area that sets us apart is superior financial performance. We have generated best in class return on capital employed throughout the business cycle. During the last five years or downstream in chemical businesses generated $46 billion of earnings nearly as much as Shell, BP, Chevron and the Total combined.
First we’ll turn to the downstream where we continued to increase our advantage relative to the competition by selectively investing in our strategic assets. These investments capitalized on ExxonMobil’s technology scale and integration to achieve the objectives listed on the slide. The first two areas lowering raw material cost and increasing high-value product yield remained regularly important. And I will discuss these in more detail in just a moment. Midstream investments will expand logistics capabilities for both crude oil and finished products with a major focus on North America.
One example is the Edmonton rail terminal that Mark mentioned earlier. In addition to providing a secure outlet for crude oil production we plan to use 100,000 barrel per day of the terminals capacity to support our refining network. On the product side we will continue to strengthen our domestic and export logistics capabilities.
Other projects will enhance our operating cost advantage. For example, building on our industry leadership position in cogeneration we recently started up a new steam and electricity cogeneration plant in our Augusta refinery in Italy, and our progressing plants for our next cogeneration project at our Singapore complex.
Our disciplined approach to managing the portfolio will continue. Since 2005, we have reduced our refining capacity by more than 1 million barrels per day and return cash to shareholders by divesting smaller less competitive facilities. And we have completed the transition of a domestic retail fuels marketing to a more capital efficient and growing branded wholesale channel.
Lowering raw material cost will continue to be a major focus area particularly in North America where new crude oil supplies are creating unique opportunities. With our integrated position in upstream and downstream we are well-positioned to benefit from this growth. As shown on the chart we have the industry’s largest midcontinent and Gulf Coast refining circuit which other regions are benefiting from the growing liquid supplies. Our refining portfolio in this region is among the most efficient in the industry.
During the last few years we have expanded our advantaged American crude runs by 40% and have additional capacity still available. Given our installed capacity and existing feedstock flexibility our investments in this area continue to be incremental and completed during maintenance turnaround. One example is a metallurgy upgrade that’s currently progressing at our Barmer (Ph) refinery. The project will expand heavy Canadian crude processing capacity by 45,000 barrels per day and is scheduled to be completed later this year.
Some of our investments are focused on increasing the yield of high-value products such as diesel, jet fuel, and lubricants. For example, we recently commissioned a new 62,000 barrel per day Ultra Low Sulphur Diesel unit in Singapore, and our new diesels desulphurisation plant in Saudi Arabia is nearly complete. We are currently developing a project to install a 50,000 barrel per day Delayed Coker at our Antwerp refinery in Belgium, our largest and most efficient refinery in Europe. If approved the new facility will upgrade bunker fuel currently produced in our Northern European refineries to high-value products including premium ultra-low sulfur diesel.
We continue to grow our premium lubricants business with four projects currently under construction to expand high performance lubricant base stock capacity. These new facilities will use our latest technology to manufacture synthetic base stocks in Baytown and Baton Rouge and premium hydroprocessed basestocks in Baytown and in Singapore. All four projects are expected to be completed within the next year and will build on ExxonMobil strong manufacturing base at these worldscale integrated facilities.
And finally we are expanding finished lubricant production manufacturing capacity in Finland and in China to support the growing sales of four industry leading products such as Mobil 1, Mobil SHC, Mobil Super, and Mobil Delvac 1. We achieved record sales of each of these premium products in 2013. And we are expanding manufacturing capability in Louisiana to maximize production of our latest generation synthetic aviation turbine oil, Mobil Jet Oil 387. ExxonMobil’s disciplined investment extends to our chemical business. Here too our corporate values and integrated approach are producing results. In our chemical business we continue to achieve industry leading returns in all phases of the business cycle. As we look to the future we are progressing several strategic investments, I’ll discuss three of the most significant, specifically on our investments in the United States, in Saudi Arabia and in Singapore. To build on our competitive advantage we continue to invest in world scale projects to capture advantage feedstocks, reduce production costs and increase high value of product sales. These projects build on our unmatched integration with the upstream and downstream and are positioned to help us serve major growth markets.
As the largest US chemical manufacturer and the largest US natural gas producer we are progressing a project to upgrade our equity ethane molecules to premium metallocene polyethylene products. In addition to capitalizing on the abundance of low cost ethane feedstock the project will be enhanced by advantages and integration, scale and premium products. As shown on the chart we have increased the amount of low cost ethane feedstock to our steam crackers in the United States and produce a higher percentage of ethylene from ethane than the industry average. In fact our existing capability to process ethane already leads the industry. We will extend that capability with a 1.5 million ton per year world scale ethylene plant that will built at our site in Baytown, Texas. We’ll maximize the value of integration through coordination with the upstream and by integrating the new plan into our Baytown site, already the country’s largest refinery chemical complex.
In addition we are building two of the largest polyethylene production lines in industry at the nearby Mont Belvieu plastics plant to convert the new ethylene production to a mixed slate of polyethylene products, including our premium metallocene polyethylene. We have completed front end engineering for the project and construction is about to begin at the Mont Belvieu site. We are finalizing the permitting for the ethylene plant and start up is planned for 2017 pending final project approval. In Saudi Arabia we are working with our joint venture project, joint venture partner Saudi Basic Industries Corporation to extend the range of products we produce in the kingdom. A new 400,000 ton per year world scale facility will produce specialty synthetic rubbers, polyolefin elastomers and carbon black. And will be integrated into our plant in Al Zubair on the Arabian Gulf. This provides a low cost manufacturing structure and leverages on our existing supply chain capabilities. The project will help create a low cost rubber and elastomer value chain in Saudi Arabia and provide a strategic platform to help meet the growing demand for rubber based automotive, construction and appliance products in the kingdom, the Middle East and in Asia. Construction is on plan, on budget and startup is expected in 2015.
Last year we highlighted the completion of our Singapore expansion project. This was the largest and most technically challenging project in ExxonMobil chemicals’ 90 year history. In mid-2013, we successfully started up the new ethylene-based complex; the project was made possible by dozens of new proprietary technologies. For instance, our world scale steam cracker can produce ethylene from an unprecedented range of feedstocks, from light gases to heavy liquids including whole crude oil, a first for the industry. We’ve also installed our full suite of energy efficient technologies to lower energy cost. And we are producing some of our more advanced plastics and synthetic rubbers for the first time in Asia and among the largest capacity units in the world. Singapore is now our largest integrated manufacturing facility and is well positioned to serve the rapidly growing markets in Asia and beyond. With the addition of the second steam cracker, the site has a wide range of byproduct molecules that can be upgraded to specialty products.
To capture this value we recently approved a project to add facilities to produce premium synthetic rubber to support the growing tire market and premium resins for adhesive applications such as packaging, wood working and fabrics. We are a leading global supplier in both of these high growth product lines. This new world scale units will benefit from advantage feedstocks on the site, in fact our 90,000 ton per year adhesive unit will be the largest in the world with capacity 40% higher than the current world scale. Integration with the large chemical and refinery complex will enable lower capital and production cost by leveraging the existing site utilities, infrastructure and organization. And the Singapore location enables lower supply chain costs and duty free access to China. Construction of the new facilities have started to begin in the second half of 2014 with startup plan in 2017.
Ultimately, we judged 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. And we constantly deliver strong cash flow that contributes to shareholder distribution.
Our leading financial performances enhanced by proven business strategies and resilient competitive advantages including our integrated model, our balanced portfolio and proprietary technologies that increased the value of our products. Our focus on operational excellence yields strong safety in environmental performance as well as reliability benefit, excellent customer service and cost savings.
Our disciplined capital management results in the best asset mix in the business, we continually upgrade the portfolio in thoughtful ways that build shareholder value. Our new investments are concentrated on our integrated site, and then are designed to capture advantage feed stocks, reduce operating costs and grow high value products to further strengthen our portfolio and provide superior returns throughout the business cycle.
We have a high performing workforce around the world, our employees are the best of the best and their dedication produces the results I have shared today. Altogether we have the best downstream in chemical business in the industry and we’re well positioned to extend our lead in the years to come. And now I’ll turn it over to David.
Thank you Mike, at this point we’ll take a quick break and I would like to limit the time to about 15 minutes and then when we come back Rex will provide a summary some closing comments and that will be followed by our question-and-answer session. So please plan to be back in your seats and ready to go at about 10:55 so we can have a full hour for the Q&A session. Thank you.
Unidentified company representative
If I can ask everyone to take your seats. We’d like to get started here shortly so we can keep our commitment to give you a full hour of question and answer session.
Thank you, so we’ll go ahead and get started and I’m going to turn the program back over to Rex.
Well again thank you, thank you all for your kind attention during the first session, I do hope that we’ve provided you with an appreciation of how ExxonMobil is positioned and the steps we’ve taken to position ourselves to deliver profitable growth and maximize shareholder value over the long term, that is, has been, is, and will always be our commitment. Now before we conclude I just want to provide a brief summary of what we reviewed with you this morning. As you saw when I showed this chart, our success is really underpinned by proven business strategies that have served us well, resilient competitive advantages including what we believe is an advantage in our integrated model, balanced portfolio of high quality assets on which we can put our talent to work, our commitment to operational excellence and as always our development of new proprietary technologies to enable all of things that we have shown you we have done and can do. We expect the key elements shown on this chart to generate cash flow growth to fund the attractive investment opportunities and to maintain superior returns to shareholders.
Upstream production volume growth focused on liquids and liquids linked gas will improve our portfolio of mix and as you have heard improve our unit profitability. And as discussed earlier, we did make some very deliberate strategic choices and take specific actions to improve upstream profitability. Feedstock flexibility, operating efficiency, high value products growth remain particularly important in our downstream and chemical business. And our disciplined capital investment processes ensure we have competitive assets to deliver industry leading returns on capital employed and generate robust cash flow growth. And we continue to evaluate and upgrade the business portfolio in ways to create long-term shareholder value.
So, I will leave you with the key messages on this screen which we review throughout the presentation. In conclusion, in my view ExxonMobil is well positioned to provide the technological and industry leadership to meet the world’s growing energy needs and I say in responsible way. Our portfolio of assets and our long-term investments are the basis for delivering future shareholder value and will provide the energy needed to fuel global economic growth and advancement in an ever changing dynamic market and an ever changing and dynamic world. I do thank all of you for your interest in ExxonMobil and all of you for join us both here or on the webcast, to the telephone that were listening to our story today and joined us for the presentation. And we are going to move to the chairs over here to my right, so that we can have an open discussion, take questions and hopefully provide additional insights to you. Management committee will join me.
I would ask that each of you limit your questions to two per person to give the opportunity for others to ask questions and I will try to be polite and knock you off.
Douglas Terreson - ISI Group
Doug Terreson, ISI. Your point is taken about how the company and its peers should be judged over the longer term and given the longer term and capital intensive nature of the business, at the same time pretty much all of the super majors having unperformed in the market over the past five or six years and that might be too short of a period but either way the market appears to believe the growth in the current profiles may be appear to writing in relation to alternative as an investment. So, I have got a couple of questions, one, do you believe that the super majors have become too large to grow and create economic value and the effect of competitive way that they have in years past? And then second, do you think the plan to increase free cash flow to I think on flood, 34 will address the issue for the company? Two questions and why or why not?
Okay. Well, I think its valid question to ask whether the super major, not just the under graded model but also the size, is that a viable long-term competitive way to participate in this space as an investor. And I guess our view obviously continues to be that it is, we continue to believe we have an important role to play as we alluded to several times, and supplying and meeting the world’s global energy need which includes those of United States. And we know that as we have seen the world change over the last couple of decades both in terms of what happens geopolitically with the emerging countries but also what has happened with the participation of new competitors into that space. And it is difficult to compete and be successful without the scale and capabilities that organizations like ours have and to manage the risk. And it’s really that second piece and we try not to over or belabor our risk management aspects of our business but I think if there is anything that distinguishes why there is still that role for us there, it is an our ability to manage complex risk by having exposures across a broad range of opportunities. And as you heard alluded to you before we don’t have any one project, there is no one country, there is no one thing that we live and die by, and that’s part of the model that we offer to investors. So certainly at any given time and we have to compete first in the sector in which we’re in, we have to be competitive and that’s always our desire and our pursuit is to be the best among this sector first. So the people want to invest in this sector, you want to own us.
And our sector has to compete in the broader choices that investors have, and that’s difficult for us to influence much. So what we have to do is compete within our sector and be the best. And to be the best at managing the broad array of risk. So at any given point in time it does not surprise main order, I am sure does surprise any of you, there will be a company that’s perhaps smaller in network and they focused to be participating in a segment or what I call our sector.
We may -- outperformers, the risk with which one may invest in that entity I believe there is a higher risk profile, because things and we do see things happen that can dramatically change the future of an entity like that, and I don’t want to speak for what their objectives are that may or may not be built for the long-term shareholder value return proposition that we’re offering. So I do appreciate that as particularly in the way markets are traded today in the ease with which people can move their investment choices around, it’s a challenge as to how do we maintain that shareholder competitiveness. Because I think we have to just concentrate on the things that we’re committed to do and that’s manage this risk more effectively, more successfully than any of our competitors and that includes all of the elements of risk, not just the ones people think about in terms of safety and operational and environmental but investment risks, geopolitical risk all of those things, and to manage that better than anyone else.
So for us we know that is the space that we occupy out there, and there are fewer others perhaps in many respects occupying this space today. The second question?
Douglas Terreson - ISI Group
Yeah, well in terms of my confidence around the delivery of that?
Douglas Terreson - ISI Group
And again I am not sure I am making the connection Doug on this free cash as an indicator that investors should be looking at.
Douglas Terreson - ISI Group
Well I think that will be up to the market to decide, whether they feel it addresses it or not. I think we have been talking for the last few years about how we rim this period of very heavy recapitalization of business, replenishing the opportunity base, because part of our strategy of maintaining a disciplined selective investment strategy requires you to have a robust inventory of opportunities from which to choose. And so a lot of what we have done over the last few years have been to create a more robust inventories of opportunities from which we can select. And we have been implementing some of those.
So we do believe the cash flow has had an inflection point as a result of many of the large projects that both Mark and Andy talked about in terms of startup. So going forward we are confident in terms of our ability to deliver on the commitments we made to shareholders in terms of maintaining again, we will be active investors because we have a rich inventory, but maintaining that commitment to return substantial cash to shareholders and we showed you the chart where we have returned 50% well above what our competitors have done. And so we intend to maintain that kind of commitment to our shareholders.
So the market will decide is that good enough?
Robert Kessler - Tudor, Pickering, Holt & Co
It’s Robert Kessler from Tudor Pickering. Somewhat as a follow on to that discussion, you highlighted early in the presentation that the significant payout ratio for ExxonMobil’s cash flow being twice that of your closest peer. It somewhat begs the question, is that positively correlated to the size or is that a choice in itself. I always thought of ExxonMobil is deciding first to invest in all attractive projects and whatever is left over is the available cash flow, you grow the dividend, you distribute by buyback. So is it a natural conclusion that the larger you get is only a certain number of projects out there, it’s naturally you’re going to start to distribute a larger percentage to your cash flow just structurally, question one.
And then question two is the outlook for pending final investment decisions for this year and next, what’s on the dock in terms of specific projects that you might be trying to invest in.
Well I think you have described us perfectly, nothing has changed. And so the free cash flow and the distribution back to shareholder as an outcome not doesn’t govern the decisions we make around investment programs. What really governs the level of investment programs is the quality the opportunities that are on offer to us and our judgment around our ability to execute them well and that’s largely limited by what we view our organizational capacity to be. And so we’re not, we may have other opportunities available so what we do is we try to hold those, we sort them try to go after the most attractive first, try to keep the others in our inventory through the lowest possible holding cost that we feel that mature to a point that they are either competitive with our standards or that we’ve got the capacity now to go execute.
So the remaining free cash flow then is just as you described we want to that we fund it all as investments we paid all our cost is maintain our dividend of course the dividends which has been through trying to raise that dividend every year which we’ve done successfully and then return the balance through the treasury share purchase program which we’ve always described is kind of the flywheel. And that’s nothing’s really changed around that. So to the extent there is more available because of our size and scale and because we are taking in effect a I hate to use the word measured but a deliberate approach to our capital investment programs that to the extent the market from time to time delivers more value then it’s our size is going to capture that. So I think you have it described particularly and nothing has changed about the way we make decisions or the way we build our strategic plans and our investment programs.
In terms of projects that are pending FID this year I’ll just I’ll ask my colleagues here to just comment on any of those that I think they eluded to a few them but I don’t know Mike if you want to start?
Yes. I think I mentioned in my talk that North America that going cracker [ph] and the coker and into it.
Yes. I think on the project front it would be the [indiscernible] expansion take in production from 600 kbd up to 850 kbd which will be a major investment decision this year.
Yes, either one -- and then you had the microphone over just go [indiscernible].
Paul Cheng - Barclays Capital
Hi. Thank you. Paul Cheng, Barclays. Rex, two questions if we look along your global supply chain is there any particular areas there now in terms of accelerating cost inflation and any area that actually is steep the other way be accelerating? And in the area that you see accelerating what’s the steps that you guys maybe taking trying to handle that?
Well, as it’s being described and for the last few years now we’ve been and some people call it an overheated market just because of the very high levels of investment activity by everyone in the industry. I think we have begun to see some break in that in some areas it maybe short loan could be temporary the areas I would mention that is are in rigs both deepwater rigs as well as certainly in North America here there is a large rig fleet available. And so we have been able to and you saw it in some of the numbers that were described we’ve been able to drive the cost of our unconventional programs down on a per well basis. A lot of that is through process and efficiency improvements and applications and new techniques but some other is capturing that market as well.
So as we sit here on this looking at the U.S. unconventional opportunity set we do kind of constantly look at okay well what would be the cost of picking up that next increment and is that attractive enough for to do that. But in terms of a wholesale shift in terms of the inflationary pressure or the overheated market pressures although we can point to anything substantial and so that just the signal back to us and to our organization is you’re going to have to create that you going to have to create it through different engineering solutions, we’ve got to create it through good procurement and contracting strategies and sure we’re not leaving a lot on the table. But not sacrifices the quality of what we have to have in terms of whether it’s materials and services or whether it’s the contractors who working for us because we try to be very deliberate about who works on our major projects. So I would say those are the areas we may be seeing a little bit of softening in of late whether that’s sustainable or not depends on what a lot of other people do around the world to use who buy for those same services.
Paul Cheng - Barclays Capital
Second question in the North American unconventional oil portfolio I think Mark you show, you are going to grow it into 225,000 barrels a day by 2017. And I think the chart look like while you now do around 140,000, 150,000 barrels a day so from this point on look like it’s a pretty modest growth. Is this a limitation of your manpower or organization capability limit or that you just think that you still have enough, delineation need to be done. Thank you.
Well Mark showed the chart but I’m going to ask Andy to answer the question because XTO reports to him.
Yes, it’s a function for the investment decisions we’re making and what we think the prudent way that ramping up the execution of the drilling programs in different basins. As Rex talked about before organizational capacity the ability to execute something we look at very carefully, we don’t want to over run our headlights on that. So as we look at this progress particularly on very hard areas the Permian to some extent the Bakken and so forth. We think very carefully about how we want to keep driving the programs forward with the pace of picking up rigs and crews and so forth and that is the plan this year. As with the gas plan, it is also somewhat adjustable as we go forward on time we will continue to look at that.
Doug Leggate - Bank of America-Merrill Lynch
Thanks Rex, Doug Leggate from Bank of America. Two somewhat related questions, the premise being that Exxon plans in a very long-term time horizon. When you look at last year’s outlook the CapEx number is not much lower this year but the production is done 500,000 barrels a day in 2017. So I realize I had not been here but can you help us reconcile the GAAP asset sales a significant part of the equation? And the follow on is that again in the basis long-term planning horizons you have suggested that 2013 you’re expanding and you have this free cash flow. So what’s some of these major projects that Andy lined out are approved, there is the CapEx number change as 2013 move along and how much of the free cash flow inflection is actually contributed from those assets?
Well I think the question around the volumes being lower the CapEx being unchanged. If you look at the volumes that came out, things like the Abu Dhabi onshore concession. They had very low CapEx attached to them. So there was much relative to when we showed you this outlook last year versus this year, there were not lot of CapEx attached to those volumes have they stay down. So I think kind of rebasing things and there was also no volume growth in those, that’s why when you look at that chart it comes out as a constant slice, because there was also no volume growth. So what we really did is we took a set of low margin barrels off the base, and all the growth and the capital that goes with the growth is still attached to the barrels that are in the growth. But the simplest way I know to respond about and the second question.
Doug Leggate - Bank of America-Merrill Lynch
There is some divestments out of there which also had very little CapEx attached to them. I think I say if you just look at that wedge of what came out, there wasn’t a lot of CapEx attached to that, which is also why there wasn’t much of a growth component in it, it was pretty base kind of volumes.
So like I said I think, when you think as it comes off the bottom off the base because there wasn’t a lot of growth contribution from it.
Doug Leggate - Bank of America-Merrill Lynch
My second question was pretty much of the free cash flow inflection comes from related asset tails that might be contributing to the drop in volumes?
Well I think you had actually two questions, one was has all that stuffed in the CapEx outlook and it is, so we made assumptions about FID or expenditure right, most of the projects that are in there are either about to be FID or they already are underway. So we have a CapEx profile for the future, it goes with those. In terms of the amount of free cash flow that’s generated from our net asset sales and acquisitions and that’s not really how we -- I don’t want to miss, I only misinterpreted that’s how we necessarily manage it.
And we manage the portfolio, we look at the asset quality and if we have some things that we believe have a higher value to others in the market then we’ll go out and test that. Likewise if there’s something that comes along that looks interesting to us and we think it kind of has good long-term value then we’re not constrained by saying well, buy this to ourselves or something, we don’t have that kind of a model; because we have sufficient balance sheet strength to go do whatever we want to do.
Having said that if you kind of look over last five years, there is probably a net of about asset sales versus asset acquisitions. There’s probably a net across the five year period of about $5 million and you can go -- you can look at our past relations on things that we’ve sold of exited or restructured, call it different things. And things we bought and if you summed it all up, it’s probably about $5 million.
So it’s not a huge component. It’s really more about our strategy and our tactic of just constantly looking at our asset holdings and saying we could put the people who are spending their time on this, on something of much higher value plus see what the market might give us for, good time to exit. And we see we have better opportunities over here to deploy both our financial resources, but our human talent as well. And so that’s really more what’s at the heart of our asset. We call it asset management program and that’s really the stuff we sell and from time to time we buy. Now on a go forward basis, that’s part of I know what frustrates everyone. We do not forecast -- typically we do not include asset sales in our forecast for obvious reasons. We do not want to signal anybody that we're going to do anything.
Over here yes, Arjun.
Arjun Murti - Goldman Sachs
It’s Arjun Murti with Goldman Sachs. My question was on the unit profitability metric that you've talked about even more this year after last year. I think Robert said it earlier and you agreed, you've been very known for returns over long periods of time, returning excess cash to shareholders. You have now introduced this unit profitability metric and we are trying to understand how this really changes how you think about portfolio decisions? The Company that’s number one, who we respect like a lot, they've got higher CapEx per barrel, lower returns on capital and lower cash distributions to shareholders. So I don’t really understand the relevance of your being number two or any other position.
In terms of one of the reasons the volume outlook was lower, you cited you didn’t want to invest in low margin barrels. The Abu Dhabi exploration makes sense but natural gas, the outlook can’t really be worse than last year. It’s got to be at least the same or better. Maybe some stuff happened to your resource base, I don’t know, maybe it’s a way to manage CapEx. But the kind of saving margin for the U.S. natural gas degradation of Boe, it doesn’t quite be logical. And we need to understand why this emphasis on unit profitability? Clearly you want the portfolio to do well but you've always focused on returns?
Yes. Well, it’s not -- unit profitability has not become the objective. It is a measure that we have found useful, in particular in communicating with our organization around how to think about where are your highest value opportunities. And this again is not anything new and using unit profitability as a tool has been with us for as long as I can remember, 30 years ago when I was with those engineers trying to figure out unit profitability and why would you invest in this or that. So, it’s really been a tool we've been using to tell the organization, look at your opportunity set, seriatim net opportunity set on the basis of whole range of parameters. One of which we want you to look at though is does this improve our overall unit profitability or does it detract from it. Okay, now that’s not the only -- obviously that’s not the only metric one looks at to decide I like this investment opportunity or not.
But I think it’s been instructive to a lot of our organization to go through that exercise of just understanding that element of quality, of the opportunity that is before them. It is -- we are constraining in some sense our capital spending levels for reasons that we've articulated, some of which is we've got to be confident we can do this well. And so sometimes it’s a function of what is in that capital mix as well. It’s one thing to be out executing a Sakhalin project or something in a remote environment like Papua New Guinea, as opposed to just cranking up low 48 drill wells, okay.
So, they all have their own unique character but at the end of it, we want the quality of the outcome, the financial result, they need to compete on the quality of that financial result. And so I think, as you pointed out on the North American gas and we have hinted at it a little bit. Obviously we're watching that situation.
We have a huge inventory drillable locations, probably something over 15,000 drillable locations but we've also been challenging the XTO organization with new things we keep, the bolt-ons. We keep giving them more stuff and we've asked them to look at the quality of that. So as Andy mentioned in setting kind of the level the program there like the Bakken, we have drillable locations, you pick up more rigs but then what? And if you start spreading your capacity to manage risk, we think that in the end will detract from shareholder value.
And the opportunity is not going anywhere. We're not losing it. The barrels are there. They are in the ground, available for our monetization when we think it’s the right time to do that or when we decide what we really need to do is pass on this next mega project and take those resources and let’s go pick up five more rigs. And we go through that analysis as well. So we have the choices of not just where to deploy a capital but really much, much more importantly where to deploy people. And we spend as much time on that as we do thinking about the capital, okay.
John [indiscernible]. With more of an unconventional focus, you kind of alluded to it a bit, but are you going to have to increase your headcount in terms of the number of people or anything towards unconventionals?
Well, we have shifted kind of -- just to follow-on to the point I was just making; we have shifted resources, human talent into XTO. As we have added some of the things, we mentioned the bolt-on, additional Bakken acreage, additional Permian acreage, the acquisitions in Canada, though we've asked XTO to help us evaluate and assess. We have moved a lot of human talent from Houston, up to Fort Worth into the XTO organization.
So we have done some of this redeployment. We are maintaining active hiring targets for engineers and geoscientists, and so far we are not finding constraints around our ability to attract the talent and bring them into the organization. We are not ready though to say, well, we've got to ramp the headcount up.
If you look at our overall headcount, I mentioned 35,000 in my opening remarks and it is down, it’s coming down, down, down. But that’s largely been a result of asset management programs in the downstream and allow that headcounts to be coming out of restructuring of the downstream organization. The upstream headcount has actually been growing slightly over the years. So we don’t think that’s going to be an issue for us but to your question, yes we do redeploy the talent and have redeployed some of it.
Okay, my next one is on project cycle time. It just seems like a lot of large-scale conventional projects are getting more protracted. How do you balance that in terms of the cycle times in your investment risks and the unconventional?
You said we are getting more -
The cycle times are getting more protracted.
More protracted, meaning it’s getting harder to do. I’m going to let Mark comment on that. I will say that, could we look at that, churn [ph] on our investment reappraisal process where most of you know we do a look back on every single capital dollar we spent. After it’s done, spent, started off, we go back and we do a reappraisal on how did that project go. How’d it go from an execution standpoint, which means schedule? How did it do on cost, where we had cost differences, why did that happen, and how is it performing financially? If it is an upstream project, how did the resource turnout? If it’s a downstream chemical process, was there something in the market that was different than we expected going in.
So we do a very rigorous project reappraisal. So we have a pretty good idea of what’s happening with our projects as opposed to -- as well as projects that we don’t operate, that we’ve anticipated [ph] on. And so when there are variances from what we expected we know and understand why that happened, so that next time we undertake a project, we learn, probably [indiscernible] but generally I'll let Mark comment on how we view cycle time with project execution.
So building on that, with the reappraisals we do, a few exceptions of the projects. Even though there’s pressure on the industry, as we talked about in this -- kind of previous overheated regime we’re going through it now, things are adjusting a bit here and there. But with few exceptions we have generally been able to hold the conventional projects within schedule. Some are few months ahead, some are few months behind. So we have a pretty good feel of what it’s going to take going forward. And we’re not cooking in any additional time, other than what we think is appropriate.
But to the end of your question, when we compare that then with unconventional opportunities, the way we look at it is, we look at a large conventional project. We won't compare that to a few single wells. And for example in the Bakken, we look at, [indiscernible] with a comparable size resource in production profile in the Bakken, maybe that’s five rigs, or seven rigs, or eight rigs; how do we compare those two decisions. And that’s another process we go through.
I think in terms of stock, and I'll just point to two projects very current for us. As you heard, Mark mentioned Papua New Guinea. It looks like it’s probably going to start off early relative to what we had IDed it, just superb job of execution by the project team there in an extraordinarily difficult environment. Kearl, as you know started up late, and it started up late because of the issues we had transporting modules from Korea to Washington, Idaho, Montana up to Alberta and via while you said the side of that [ph], that’s just a horrific example of how messed up our permitting process in United States is, if that ever happens. We certainly learned from it and we didn’t do it that way on the Kearl expansion project. And the Kearl expansion project is running ahead of schedule. Okay so we plot in the learnings, we thought we had that problem solved on the initial project, ran into it. So we learned; we changed the execution plan on the expansion project and it's now ahead of schedule. So I think that’s how we would talk about ours. We don’t comment too much on what others do. But we do try to help them when we're investing with them.
Evan Calio - Morgan Stanley
Evan Calio of Morgan Stanley. First question on production. Your total volume growth on the upstream has been elusive, not just in ‘13 and ’14 for all the way back into 2006. Can you discuss the assumptions on the base, in your production whether that be TSV effects, uptime, decline rates, and whether you are including a buffer? Because I know that many of the risks that you cited to your production guidance seem to be recently consistent. Is there a buffer in your volume guidance ramp? The second question.
We don’t put a management adjustment in there, if that’s what you’re asking? And that’s why we give you that long list of variables that are difficult for even us to predict, all those factors you mentioned. In terms of our base, we have -- I think we disclosed a base decline number of about 3% and that has been changing gradually over the last 10 to 15 years. It used to five. It's reflective of these big projects we talk about that come on with these fairly blocky volumes like Kearl is coming on. But look I appreciate that when we come in here and give you a production forecast and then we try to qualify it -- okay now, here's all the things that can change and what I can tell you is we are committed to deliver on our investments. That’s what we’re committed to do. And we’re committed to deliver on our work programs, on our operations and to manage those risks well so that we have a viable entity.
So we don’t take those outlooks lightly but we’re also not bound by them to do things that don’t make sense. And that’s why this shift we took last year, where we looked at that volume plan we had and we said look, if we really want to get the most out of our investment dollars and our resources, human resources as well, there are some things that probably all come out of here and we did. So that’s what we did. So we’re not -- we have never had volume targets as a key objective for us. We’ve always said it’s about delivering the value. So I know that that creates problems for some of you I think someone wrote in something I read that well maybe we -- since we don’t ever hit it, maybe we should stop giving it. I can do that. You wouldn’t have to worry about it.
Evan Calio - Morgan Stanley
My second question is you know the terms in both Iraq and Abu Dhabi improved. And given the increased resource opportunity globally, both unconventional and new countries opening and this whole notion -- industry notion of peak CapEx is upon us or behind us, do you believe there's a key inflection for PSE terms as they compete for a shrinking capital base? And then secondly, given your demand outlook on the consumption side what oil price -- I know there's multiple variables -- changes that outcome? Because it seems to me that industry CapEx notion is inconsistent with the forward commodity curve. How is that?
Well, in terms of how that is influencing government’s willingness to reexamine their fiscal troughs [ph], which I think is your question; we’re starting to see some effect of that and we were talking a little bit in the break that many of you know the long history of Alaska Gas development and now the state has kind of woken up to the fact that they’re not the only game in town and they’re seeing all these projects in Canada being talked about and they’re seeing exports out of the Gulf Coast being talked about and suddenly they realized, the world may not care whether Alaska Gas ever gets developed.
I think it has served a purpose to refocus them at -- you’re always in a competitive world. You as a resource owner, you’re in a competitor world and I think that’s been an important realization on the part of some resource owners around the world because I think for a long time they never recognize that they as resource owners were in a competitive environment. They always thought of us as being in a competitive environment and recognizing that we were competing and vying for access to their resources and that was good for them.
I think it has only perhaps begun to be realized by many resource owners around the world that because of this now air of abundance that we talk, that they’re in competition. When do their resources get developed or do they get developed at all? And so I think I wouldn’t -- it’s always dangerous to make generalizations and so I wouldn’t say that that is the case everywhere but it certainly is the case in some places and it has made I think made for a more productive conversion around what does it take to develop your resource and for your nation to realize the benefit of that and us as the investor to be able to take the risk and realize the benefit for our shareholders. I think there's a much more productive conversation now that occurs around that that perhaps it did in times past.
In terms of what price changes all of that, you know me. I never talk about prices. And it’s more, I think it has as much to do with the fact that there's a lot of resource coming on the market out there and there is a general realization of that now. And it is about at what price. A lot [ph] are beginning to get me. So I may have a little trouble seeing [ph].
Edward Westlake - Credit Suisse
It’s Edward Westlake, Credit Suisse. My first question is really around North American crude growth you’ve given us 1.5 million acres in the Permian, which if you speak to an E&P company will translates into many, many thousands and thousands of barrels. But on the refining side the market is concerned that we cannot process that. So can you talk about the limits that you see in terms of being able to process the light oil and if you do see limits, what the industry needs to have happen to alleviate those limits? That’s my first question.
Well, we obviously do ask ourselves that question and then we ask our supply and refining folks who really know this well to look at that I’m going to let Mike respond to that because we actually have had recent conversation about it.
Well, I think if you look globally at refining capacity, there is a length of distillation capacity in the world, and so there’s an overhang on the whole system because of that and there’s -- there are some shutdowns that have been announced to take some of that probably off, but there’s still some that has to come. So there’s some parts of the world where refining margins are going to be difficult and people going to have some tough choices. The Atlantic Basin is probably one of the places for that. There are our competitors of ours who are in the Atlantic Basin. We're bringing crude from -- some of the midcontinent crude, some of the lower priced, discounted crudes to try to keep those refineries going.
So you know there is a dynamic there about how does this keep going and then when you look at well, do you want to invest? If you were an investor would you like to invest in a grassroots refinery or a multibillion dollar expansion to accommodate light crude, you still have to come to grips with the fact that there’s a surplus of crude in barrels can move. There are limitations by government and things that have to be overcome but the barrels can move but you’re still on the ground [indiscernible]. So I think there’s, it’s difficult to predict exactly how this is going to happen. For us we’re still not using all of our capacity to run the light crude. We’ve got our Midwest system loaded up at predominantly the heavier crudes, the Canadian crudes. We’ve got our Gulf Coast system running both light and heavy and we still have capacity. We’re constrained more by logistics. Whenever we do a turnaround and we’ve had a pretty busy turnaround time we do, [indiscernible] to take advantage of these crudes when they present themselves on the market. So we still seek [ph], certainly on our system the opportunity to process more of these crudes. We may get to the point though where that explored option becomes much more important. Then we’ll see where the government comes out on that.
Edward Westlake - Credit Suisse
Second question, I appreciate, you may not want to talk about the explicit timing of some of these non-operated megaprojects which you called out in your opening remarks, specifically Kashagan and potentially Gorgon but as you think about your longer term production that you presented today, when is the sort of the first full year that you feel Exxon shareholders can sort of bank on the cash flows from those projects?
I’m going to let Mark comment again in terms of what was kind of built into that chart I showed you when we looked at those major projects around, and particularly the restart at Kashagan and then I guess Gorgon was the other one you asked about.
So if you look at Gorgon first, startups going to be in 2015. So the first full year to answer your question will be in 2016. We’ll startup initially one -- the operator will start up one train and then the second and then the third. So the first full year of the first train will be in ’16.
On Kashagan as you all have heard, the consortium is going through and analyzing this, but so far it’s stress cracking issue that’s occurred in both the oil line and the gas line and little premature to speculate on when that next startup quite frankly because we’ve gotten a lot of data in but we still need to get the smart pig, these high instrumentation sensing pigs through both lines, incorporate all that data and then assess them, are we replacing a number of joints, we’re replacing half a line, a full line, both lines, what do we have in front of us. So we've put some rest [ph] in our Kashagan outlook and see the first full year of Kashagan restarting in ’15.
Asit Sen - Cowen & Company
Asit Sen from Cowen & Company. Two questions, first one on the slide on high grading the basin, it being a deliberate choice, looking at the 2017 delta, 500,000 barrels a day, if you take out Adnoc 140 and maybe West Qurna about 50, that leaves about 300 a delta? Would that mostly be in U.S. gas? I'm looking at just 2017.
If you meant my remarks I think I mentioned it was, there’s North American gas, the way you have -- and the outlook, a lot of it continued to just come down, but there’re also the impacts of some of these projects delays, are in there as well which pushed, some of which would have been hitting their peaks. They’ve been pushed out because they’re delayed starting up. So it’s a combination of those and then some other puts and takes on divestments that make up the balance of all of that.
Asit Sen - Cowen & Company
And the second question is on Iraqi fiscal terms. I think you mentioned net income per barrel, closer to the global average. Did I hear that right and how does this change the long term future in the country?
Well, I think that’s what Mark indicated in his remarks is that the structure of those contracts have been redone for a lot of the participants as you’ve been reading. As Iraq decided their original aspirational plateau, though it was not in their best interest and they wanted to lower that plateau volume, they needed to offset the full value of the commitments we made, because it’s a multiyear, multi-decade contract, and when they lowered that they took a lot of the value out, for investments that we would have made now that we would have collected some fees on in the years to come. So there’s been, and I don’t want to say more than it’s appropriate to say but there’s been a fair amount of restructuring with those agreements, so that it does now deliver a value that’s more in line with our average or approaches our average.
In terms of what that means more broadly in Iraq, I'm not sure much of anything right now because they have their hands pretty full with just continuing to execute these various agreements and concessions that they already have in place. And so I don’t think it is -- from my perspective it’s not cost [ph] them. You have to revisit their whole approach to what they might do with future concessions. And I think they’re spending a lot of time on that. I think there are spending most of their time on, okay how do we execute what we've got; because it’s an enormous amount of work that they have underway now. And as you know under these arrangements, we execute through their oil companies, the southern oil company, the northern oil company. And so they have a capacity issue as well. So in terms of what that might mean, when they get around and want to introduce some new concessions, I think it’s far too premature to know - back in Vector [ph], just going to keep working my way around here.
Faisal Khan - Citigroup
Faisal Khan with Citigroup. Rex, now that you’ve set production guidance to lower your free cash flows going up, how are you thinking about acquisitions and more specifically transformative transactions on large-scale acquisitions or bolt-on acquisitions?
Well, not knowing to signal anything about the future, but I think it’s instructive to look at what we've been doing, and as you've seen we’ve been opportunistic on what we've described as bolt-ons, and we have done those through a number of different ways of bringing those transactions about. Some are just outright purchases, some of them involve trades, some of them involve trades, commercial arrangements that were in the interest of the counter party. So we’ve also -- our people have been very creative about how to acquire those at what we believe is a very good value for us.
And so they, we have some folks that are constantly looking, and a lot of things are coming to us, shouldn’t surprise you. Things walk through the door every day. And we try to do a quick, we're interested or we’re not interested kind of a determination. But I think -- our approach as you've seen in the past is not going to be too different in the future. We're going to be very opportunistic around those things that really we believe add value, and add value within our capacity to execute them and realize the value. Because they don’t come with a lot of other obligations. That’s what we’ve been largely doing.
Faisal Khan - Citigroup
And it’s a follow-up on Russia; you guys have been spending a decent amount of exploration dollars there due to recent events that have changed your political risk of operating in that country, or do you continue looking forward [ph]?
Well, as you’ve heard we have a fairly active exploration program plan for the high Arctic. Our Sakhalin project is in execution stage on Arkutun-Dagi, and everything is performing well. There’s been no, I mean to this point, the current situation obviously is early days; no impact on any of our plans or activities at it this point and nor would we expect there to be any, barring governments, taking steps that are beyond our control, that we can’t do anything about. But in terms of our view of country risk, our view of the geopolitical risk, and your ability to manage that, other than things like sanctions which have affected us before, we don’t see any new challenges out of the current situation.
[indiscernible]. I have a broad possibly oversimplified question. But conventional wisdom is quickly becoming that North America will be able to supply all of the CERN [ph] energy needs an begin exploring in the immediate future, while at the same time many regions of the world have become increasingly unreliable as sources of the energy, most recently Ukraine and Venezuela. Assuming this trend continues, do you consider this net-net a positive, and you’ll be able to operate in more stable areas of the world, or negative given your exposure now to high-risk areas, or are you agnostic to that trend?
I’m not agnostic because I'm a free trade proponent, and I think net-net it’s positive for everyone first, but it’s positive for us. Any time you eliminate barriers to our ability to move our feedstocks, our products, our molecules around to get -- to achieve the highest value, that’s a good thing for us. And I think it’s a good thing for U.S. economic and trade policy as well. I mean that’s the pitch we make always is -- this is a great opportunity to allow the U.S. to get the highest value for its own natural resources and to allow the manufacturers that utilize these molecules, whether you're a refiner of petrochemical plants or industrial process that uses natural gas or whatever to have access to the best slate of feedstocks they can put their hands on.
And so for a refinery in the U.S., kind of backed to, with regard to your question to Mike, for refinery in the U.S. would really rather run on imported foreign crude because that gives them a higher margin for their configuration, and that surplus is a bunch of Eagle Ford or Bakken or Permian or whatever barrels, that someone offshore would love to have.
That’s a good thing, that’s a great thing. And so we’re not agnostic to it at all. We are proponents of removing those trade barriers. And we will deal. We are happy to complete in every country and every resource, every facility we have. We are more than happy and welcome to take on the competitive challenges that come if in fact that the global marketplace is open to everybody. We'd love that. We thrive on that. And so we are not agnostic. We are pro free trade.
Roger Read - Wells Fargo
Roger Read, Wells Fargo. I’m just one last one question, because a lot of them have been asked [ph] but specific to the tight oil forecast in the early part of the macro -- granted it's tough to draw the line exactly right here, but it looks like it’s not a terribly large amount of growth in tight oil going forward. Opinions on what that means is you’re looking at North America and then also with the Vaca Muerta in Argentina, kind of what that implies? It's really -- not a lot of players down there. You’re one of them. Just wondering what you’ve seen so far and how that is incorporated in the forecast?
You’re talking about in the energy outlook or -
Roger Read - Wells Fargo
Your energy outlook early on.
Well your right. It's pretty hard on micro, kept the dot right on the plot. The energy outlook simply builds up by region demand sectors and then it builds up by region supply sectors. Then it matches those up. And so it’s -- I wouldn’t read too much into whether we think the resource base is limited, which may be kind of what's underlying your question. Do we think the title resource base is limited?
The resource base is in the outlook defined as well as anyone can define it today. And we do have, when we build those long-term outlooks, we build in some components that some people refer to as grossed amount [ph], the fact that we know that the resource base typically grows over time; it rarely shrinks other than through the production of the volumes. So there is no resource constraint that we see out there on tight oil.
On the Vaca Muerta, we think it’s a high potential area. We're in the very early exploration phase. We’re not even to the appraisal delineation phase here. We literally are just -- we are getting first wells drilled on some of our blocks in our acreage. The results have been encouraging. I wouldn’t want to declare victory on it yet because we know in these very large basins, as we have committed before and you have observed even here in the U.S., where it's a mature industry, that the basins are not homogeneous. There will be parts of the basin that will be more attractive than others.
But the rocks are certainly working. I think Mark or Andy referred to a recent well test that looks very encouraging on a vertical test. So we know there’s parts of the basin that are going to perform. So we’re fairly confident that you got an unconventional resource down there. It is going to perform. It can be developed. How big it is, is still kind of the question outstanding. The other question outstanding is and does the government put in place the conditions to allow the kind of activity levels that are necessary to really see these things have a meaningful impact, a meaningful impact on global supply, but a meaningful impact for the country and for the investors.
And we all know what that means because we watch it happen every day here in North America and in the United States. We have talked to the government of Venezuela and we've met with President, we had these conversations about, look, you need to understand, the fact that it works doesn’t mean it’s ever successful. You have to put in place the conditions and it’s still -- there is a lot of discussion that’s going to be required and I think we are fortunate in that the national oil company YPF also has a big stake here, and their CEO sees things the same way we see them. He knows what it’s going to take to make this work.
So I think we have -- it’s a question of continuing to make those points with Argentinian governments and as people begin to have the kind of success where they now would like to really step up the activity level, and commercialize it, there's a government going to put conditions in place to allow that to happen. And I think that’s kind of the way I will draw the picture around Argentina.
Peter Hutton - Royal Bank of Canada
Peter Hutton from Royal Bank of Canada. Two questions, first on distribution, and second on the downstream. On distribution you are and remain always very clear about the importance of the commitment through shareholder value but sometimes a little bit less clear on what you think is the optimal balance which we return to shareholders through the dividend, and returns to shareholders through share buybacks. And we've seen strong growth in the dividend. You got a progression we would expect to see going forward. Over the last five years, the shareholder buyback is out -- the money returned through shareholder buybacks has been 2 to 1. Do you see that moving closer towards partly through your dividend buybacks? What’s the right balance in that big financial frame work?
And the second question is actually an easy one, is on the downstream you remain in the downstream ahead of your competitors in terms of returns on capital but nonetheless last year was only the second time in the last decade where those returns dipped have below 20% and the other time was in 2009 when there was the depth of the global recession. Not quite as clear that we’re in such a difficult state. What should we be thinking of as the long term target on returns in the downstream? Is 20% or above still a viable and effective number?
Well, one, we don’t give targets on that and we don’t an internal. I’m going to just speak frankly. We don’t set an internal target. We have an investment quality threshold for individual investment decisions and then our business units are challenged to be the industry leader to maintain their discipline, their operational reliability and to produce the highest return on capital they can give us. They will -- as part of their plan they will put a forecast out there. This is what we believe, they believe they will be able to generate, given these assumptions on industry margins or prices or all the things that have to go into making that assumption and we look at the reasonableness of those and then that allows us to make our plans regarding investment levels, cash flows, kind of how do we want to manage the business over the near term.
So we don’t have guidance to give you on return levels. What I would tell is we intend to be the leader. We have been and we intend to continue to be the leader and by how much? Largely a lot of that depends on the market conditions themselves. As you’ve seen on those historical plots, we tend to do extremely well when you’re on an up cycle and we tend to go down with everyone but at the bottom of the cycle we’re always considerably better than others at the bottom of the cycle.
Your easy question, on the dividend versus share buyback policy, nothing has changed from the way we talk about this in the past. We want to fund our investment programs, we want to have a stable, growing dividend that we can offer our shareholders and if there’s anything left over, then we look at how do we want to use that excess cash? Do we want to buy shares with it or is there something else that might look interesting to do with it.
And so as we’ve always characterized the share buyback program, the T Share program is kind of the flywheel on the access cash and it’s really a question of how do you want to manage that, given the way we do our thing, we’re looking, trying to look far enough ahead to not be precipitous in anything we do. We went through a period where we had a lot of cash on the balance sheet. We don’t view cash as a particular asset and so we wanted to get that off the balance sheet and so we use that flywheel but as we bring it down we want to do that in a way that’s not precipitous and so some shifting into the dividend was prudent and we felt sustainable because we also want to be confident what we do is sustainable. And that we can maintain our hope to be able to always deliver growing dividends to our shareholder, that’s our commitment.
So no change of our philosophy of any of that and we don’t start the first year and say there's the target. We look at what cash is available to us, what opportunities are available to us, what’s leftover, what do you want to do with that. And that’s why every month we kind of announce, well here’s the T Share program for the next quarter, because depending on what happens, that’s the knob we tend to turn the most and we try to leave everything else as stable as possible.
One more question is what we got time for. Yes, right there.
Iain Reid - Bank of Montreal
It’s Iain Reid from Bank of Montreal. Just going back to your unit profitability discussion you had on the earlier rates, I wonder if you can give us a bit more detail in two important areas; one existing loan [ph] prospective. In terms of your North American unconventional businesses, is it possible to say what the units earnings were in 2013, where you hoped to reposition that with changes you’re making to the portfolio and production fixing in the gas part, and secondly in Russia, can you say what's your likely unit earnings is going to be from the Kara Sea and also the Kite [ph] all your drilling in West Siberia and how determined those are on the tax breaks, what you’re being offered there?
Well, the Kara Sea, trying to anticipate, since we haven’t found anything yet, is difficult. Obviously we went in through the joint venture and the commitment we made to explore the Kara ultimately with a view that if it is successful, this is what it would look like and that was the basis on which we then, put in front of the Russian government what you need to do to your fiscal regime to allow us the opportunity to achieve that. And all I would tell you is that if we’re successful in finding the volumes, the size of volumes that we think are there, the potential to be there and if we develop on the cost that we used in our original models under this fiscals the returns will be competitive with other opportunities that we have, just because the resources will be so enormous. I mean, you won't bill good if they're not enormous.
The West Siberia -- tied all again, this is in evaluation program. We did get some fiscals improvements in order to start that program as well and if that is successful, those fiscals will allow us to earn a return on developing those resources that is competitive. That's all I can tell you on those, because we're not going to talk specifics. On our North American profitability, I think all I could really refer you to is what we published in the K. It's in the tables, it's under the United States, that's got a lot of stuff in it but we don’t break it out.
Well listen, thank all of you again for joining us. Thank you for your interest in ExxonMobil Corporation and your questions. And safe travels to all of you.
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