Imperial Oil Limited 8K Other Events | IMO 4 Apr 12

Exhibit 99.2


EVENT:		IMPERIAL OIL
		INVESTOR DAY
REFERENCE:		CNW GROUP
TIME:		09H30 E.T.
LENGTH:		APPROXIMATELY 157 MINUTES
DATE:		MARCH 21, 2012

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JOHN CHARLTON (Investor Relations Manager, Imperial Oil Limited): Good morning and welcome. My name is John Charlton and I’m the Investor Relations Manager for Imperial Oil.

This morning, Imperial’s senior management will take you through all aspects of our business. And with us today on my left is: Bruce March, the Chairman, President, and Chief Executive Officer of Imperial Oil; Glenn Scott, the Senior Vice President, Resources; and Paul Masschelin, the Senior Vice President, Finance and Administration, and company Treasurer. And also joining us today at the back is George Bezaire, our Director of Corporate Planning.

The agenda has us finishing the formal presentations around 11:00 a.m., leaving us about an hour for your questions. When you wish to ask a question, please wait until someone gives you a microphone so participants on the webcast can hear your question. At noon, we’d be pleased if you’d join us for a casual luncheon.

Before we begin, I’d like to take a moment to review some important safety information. Here at the St. Andrew’s Club in the event of an emergency, a first stage alarm will sound. You’ll hear a slow, pulsing, intermittent signal and at this point stand by and be prepared to leave the building and listen for any further instructions over the paging system.

If it becomes necessary to evacuate, the alarm will change to a fast-pulsing, continuous signal, at which point leave the building via the nearest exit stairwell, which from here is located just outside the main entrance to this Conservatory lounge beside the women’s restroom - so just near where you came in. And the fire exits are identified by an exit sign which is lit red.

When leaving the building, follow the instructions over the voice communication system. Once you’ve exited the building, go west along King Street to the designated meeting area at St. Andrew’s Church located at 73 Simcoe Street on the southeast corner of King Street and Simcoe Street.

I’d like to draw your attention to the fact that this presentation does contain forward-looking statements and actual results may differ as a result of many factors, some of which are noted on this slide. Canadian reporting standards also require that we provide clarity with respect to the non-proved resource basis and the fourth paragraph provides for this requirement.

Unless otherwise specified, all figures are in Canadian dollars.

It’s now my pleasure to introduce our Chairman, President, and Chief Executive Officer, Bruce March.

BRUCE MARCH (Chairman, President and Chief Executive Officer, Imperial Oil Limited): Thank you John, and good morning to all of you. I’d like to welcome you to our investor conference, those who are here in person and also all of you that are following us on the webcast.

We’re really pleased to be able to share our 2011 financial and operating results, and to discuss with you in person the promising future for Imperial Oil. It’s a future that will continue to deliver superior value to our shareholders over a very long period of time.

We think we provide a unique opportunity for investors. We are a company with over 130 years of operating experience. Our assets are only in Canada. We’re embarking on a period of exceptional growth and we’re backed by the strength of our majority shareholder, ExxonMobil.

Our competitive advantages are grounded in our commitment to operating integrity, to risk management, to financial discipline, and to using technological innovation. These items underpin our strategies and will provide company growth in the long term, and better performance than our peer group. These are going to be our key themes today.

Two central trends provide the basis for our view of future energy demand. First, the global population will continue to expand, reaching nearly 9 billion people by the end of year 2040. Second, economic growth will continue with rising prosperity in developing nations creating most of the demand growth through trends such as increased consumption of electricity, and increased vehicle ownership.

As a result, global energy demand will grow substantially. Even with very significant efficient gains in OECD countries, worldwide demand by 2040 will be 30 percent greater than it is today.

The world’s energy mix will also continue to evolve over time. We expect oil and natural gas will continue to maintain their central role in meeting the world’s energy needs by virtue of their availability, versatility, and affordability. And in 2040, oil and natural gas will continue to supply about 60 percent of the global energy needs.

Natural gas will be the fastest growing major fuel, with demand rising by about 60 percent. Much of this growth will come from electric utilities and other consumers shifting away from coal in order to reduce CO₂ emissions. Somewhere between now and 2040, probably around 2025 or 2030, we expect natural gas, which emits about 60 percent less CO₂ emissions than coal when used for power generation, will likely overtake coal as the second most popular fuel after oil.

Oil and other liquid fuels will remain the world’s largest energy source in 2040. Globally, demand for liquid fuel will rise by almost 30 percent over the next 30 years, with close to 80 percent of this growth tied to transportation. While this ultimate growth rate of about of 7/10^ths of 1 percent may not be impressive by itself, what lies under this total demand oil forecast is noteworthy.

The world’s need for new oil production capacity is much larger than the predicted growth demand. New supply is also required to compensate for the decline in production at today’s existing oil fields.

This chart by the International Energy Agency estimates that crude oil output from fields in production in 2009 could drop by about 50 million barrels per day by 2035. I think all of you know, 50 million barrels a day is about four or five Saudi Arabias.

So to meet future global demand, a tremendous amount of new oil supply is required and it’ll need to come from many sources. This energy challenge will require the pursuit of all affordable and economic fuels.

A commitment to the development of new technologies will also be required, and governments need to play a major role by maintaining sound

and reliable policies that reduce investors’ uncertainty. And despite being deemed as unconventional, large basins like Canada’s oil sands will draw much attention.

Now I expect many of you have seen charts with these facts, but I think it’s important to highlight again the importance of Canada’s oil sands resource. First, you can see on the left that Canada has the third largest oil resource base in the world, and virtually all of this is concentrated in the oil sands.

But more importantly, I’d like to draw your attention to the chart on the upper right-hand side. About 78 percent of the world’s crude oil resource base is held or controlled by governments or government-controlled oil companies. Of the remaining 22 percent not owned or controlled by governments, about half of that oil is found in Canada. Clearly, to meet the growing demand for oil globally, developing Canada’s oil sands is essential.

As a result, major oil companies from around the world are all seeking to develop Canada’s oil sands. This relatively new enthusiasm for the oil sands is not new to us, however. We’ve been developing these resources for decades.

As the world looks for energy security, the supporting role of government is very important. With our expanding capital investment program, we are also very much aware of this.

The best way for governments to encourage investments is to put in place sound, efficient, market-based policies which support long-term planning and long-term investment. Such sound policies uphold the rule of law and provide stable and fair legal, tax, and regulatory frameworks.

Public policy should also promote free trade and a free flow of goods and services. From these perspectives, we believe Canada is an excellent jurisdiction for the energy industry.

Notwithstanding these advantages, we do have our challenges. Regional inflation is a concern, particularly for oil sands activity in Alberta. And labour will be in short supply again if the level of oil sands activity increases in line with all the announced projects.

Let’s now move to a review of our financial and operating results, starting as we always do with our safety and our environmental performance. Nothing receives more management attention at Imperial Oil than the safety and health of our employees, our contractors, our customers, and the people in the communities where we operate. Our vision of ‘Nobody Gets Hurt’ has been internalized in the company’s culture, and is a central and critical element of daily operational excellence.

Many of our business units have demonstrated this level of performance over many years. Our safety performance continues to be one of the best in our industry, and we are proud of this achievement. But unfortunately, our performance in 2011 did not meet our own expectations, and we will return our performance progress back towards our zero incidents goal.

Strong safety performance is a direct result of effective risk management and a relentless focus on operational excellence. At Imperial, we know that good safety performance leads us to good business performance. We also know that a safety culture has a positive effect and a positive influence on the behaviour of each employee and each contractor at our facilities.

It’s a core value at Imperial that influences decision making at all times and at each level of the organization. So we won’t be satisfied until ‘Nobody Gets Hurt’.

And let’s now look at our environmental systems and performance. All of you know and have read that meeting the world’s growing need for energy, while minimizing the impacts on the environment, is one our

industry’s biggest challenges. We have implemented ExxonMobil’s Operations Integrity Management System, or OIMS, which provides a rigorous framework that delivers ongoing improvements in safety, in health, in security, and in our environmental performance.

The results of this discipline are quite significant. One example on this chart is the two-thirds reduction in environmental compliance incidents between the years 2009 and 2011. The severity of these compliance incidents was also reduced, with none having a measurable impact on the environment.

Our management programs are comprehensive, and they’re focused on improving our performance in spills, in releases of light hydrocarbons, in flaring, in water management, and of course in energy efficiency. In our current operations - and as we develop the oil sands projects for the future - we will continue to work to Protect Tomorrow. Today.

Let’s now look at our 2011 financial results.

Overall, I am very pleased with our 2011 performance across all key measures and all business lines. We continued to achieve strong financial performance last year, achieving the second best total earnings in our company’s history at over $3.3 billion. Reflecting the value of our integrated operations, the Downstream and Chemical businesses contributed about one-third of our total earnings last year.

You can see on our chart the earnings per share were $3.95. That’s up 53 percent from 2010, and the return on average capital employed was over 25 percent.

Upstream production, supported by record volumes at Cold Lake, approached 300,000 barrels per day. And the capital investment program, with expenditures over 4 billion in high-quality growth projects, for the most part was supported by our strong internal cash flow.

To put one of these results in context, let’s take a closer look at our return on average capital employed and compare it to our competition.

Performance in our capital-intensive industry with long-life assets, we believe, is best reflected by return on average capital employed. It’s an indicator of sound long-term strategy and of disciplined investment decisions. This disciplined approach, where we manage each of our business units for the long term, helps us generate competitive advantage and value for our shareholders.

As you can see in this chart, the competitive advantage versus our Canadian peer group occurs not only when prices and margins are high, but it also occurs when prices and margins are low. The consistent

execution of our business model, where we operate safely and reliably and invest with care maintains high-quality assets in all of our business segments. These assets deliver strong earnings and superior cash flow, which is reinvested in growth projects and, in times of surplus, returned to shareholders.

We are consistently an industry leader in this measure. The ROCE for the company, including capital invested for Kearl to date, was 25 percent last year. And when we exclude capital for assets under construction, our operating ROCE was about 60 percent in 2011.

Our objective is to achieve double-digit returns in all three of our business segments, even at bottom of cycle conditions. You’ll see this later when Paul Masschelin reviews each segment’s financial performance.

When volume growth opportunities are limited, like we currently see in the Downstream and Chemical businesses, we target to keep our capital additions at less than depreciation. And for projects delivering new volumes, capital efficiency is a key priority.

Imperial’s superior return on capital employed translates into better shareholder returns when compared to the TSX Composite and the TSX Energy indices. Over one year, over five years, over 10 years, and although not shown on this chart, over 20 years, Imperial has outperformed both of these indices.

We create value for shareholders in three ways – through dividends, in capital appreciation, and in stock buyback.

Our first use for cash is dividends, and we have paid a dividend reliably for over 110 years. Then, we invest in high-quality growth opportunities. When we generate cash above and beyond these requirements, we look to return it to shareholders through share buybacks. With this formula, Imperial has delivered superior returns to shareholders for over two decades, and I believe we are well positioned with a proven strategy and superior growth opportunities to continue to do this in the coming decades.

Let’s take a quick look then at our track record of Upstream reserve growth over the last decade. When you look at reserve additions, we believe that an appropriate time context is very important. Over the long term, we have a history of growing reserves substantially. This chart shows that over the last decade we’ve increased proved reserves by more than 50 percent, and almost all of this has been the result of organic growth.

These proven reserves additions of 2.2 billion barrels have come from improved recovery at Cold Lake. and from new projects such as Kearl. These additions are about twice the cumulative production over the last decade, so our ability to replace more reserves than we produce positions us to continue to deliver profitable volume growth in the future.

Total proved reserves at year-end were about 3.2 billion oil equivalent barrels, and at our current rate of production, the proved reserve life index exceeds 35 years of coverage. And it’s important to note that 98 percent of our proved reserves are liquids.

The depth and the quality of the resource base has also improved over the past decade. Through organic growth, again, we’ve added about 6.5 billion barrels to our resource base, shown by the green bar. And even after conversion of a significant portion to proven reserves, shown in red, our resource base has increased by nearly 50 percent.

The depth and quality of this resource base supports our Upstream growth portfolio, and provides Imperial shareholders with strategic flexibility in Upstream investment options. Our non-proved resource base is about 13.3 billion barrels, and it includes about 8 billion barrels of mineable oil sands at Kearl, at Syncrude, and in the Athabasca area; about 3.5 billion barrels of in situ oil sands at Cold Lake and in the Athabasca area, and about 2 billion barrels of conventional, unconventional, and frontier resources, which includes Taglu, Horn River, tight oil, and in the Arctic.

But we’re not content to maintain the status quo here. Every year we look for high-quality opportunities for reserve additions. Last year, we acquired some shale gas and tight oil acreage and through a swap, greatly improved our acreage position in the oil sands.

Now ExxonMobil first acquired a majority position in Imperial Oil guess when? In 1898. That was when ExxonMobil acquired the majority position they have today. So by this time, I think I can definitely say that we know each other very well.

We are strategically aligned with ExxonMobil. Both companies advance opportunities that provide attractive returns across a broad range of industry and market conditions while maintaining a focus on capital efficiency and capital discipline. Both companies have a proven record of responsible stewardship of shareholders’ money, and both companies view operational excellence as its key and competitive advantage.

Imperial businesses are fully aligned with ExxonMobil’s and we benefit tremendously from their management systems. ExxonMobil executes as many capital projects in one year as Imperial Oil executes in a decade and we have open access to their project management expertise

and their project management systems. Their functional focus across all business lines also brings a large number of best practices into our businesses.

When it comes to personnel development, Imperial employees take advantage of extensive training and development programs which allows Imperial to place tomorrow’s business leaders in ExxonMobil’s worldwide operations. That helps develop their leadership and technical expertise, qualities which are required for success in this demanding energy business.

Together, we procure products and services from vendors and suppliers all over the world to get the lowest price, the highest quality, and the best terms possible. And we utilize ExxonMobil’s low-cost business centres around the world for routine support services to help lower our operating costs. So I hope you agree with me that no other publicly-traded company in Canada has this kind of a competitive advantage.

Our business model has continued unchanged for many years and is likely familiar to most of you. Many years ago, it started with investment discipline focused on long-term fundamentals and advancing just a few high-quality projects.

We apply the same rigour and same focus to our daily operations. We operate at the highest standards, meet our commitments, and in the process we typically set industry benchmarks. We do this through a disciplined and systematic use of management systems. Just as we use the OIMS system for safety and environmental performance, we also use separate management systems for business controls, a separate management system for project execution, for equipment reliability, for energy efficiency, and for product quality. We call all of this Operational Excellence, and the management systems ensure that we work rigourously to improve each of these business performance areas even further.

Throughout the business cycle and across all business lines this approach continues to deliver industry-leading returns, superior cash flow, and growth in shareholder value. This approach works in all environments, and is a transparent and straightforward method of doing business that we do not intend to change. Our financial results last year and over the past decade evidence the strength of this business model.

Now I’d like to introduce Glenn Scott. Glenn is our Senior Vice-President of the Upstream business, and he’s going to take you through our plans for growth and give you an update of where we are.

GLENN SCOTT (Senior Vice President, Resources Division, Imperial Oil Limited): Thanks, Bruce, and good morning, everybody. Welcome.

Today I’m pleased to share with you our growth plans. We’ve got plans in place to double our production over the next decade, and I’ll walk through those plans in the next few slides. But we also have a high-quality portfolio to draw from that will provide us with more growth opportunities well beyond this decade, and we’ll cover a few of those as well.

The picture shows a nighttime view of the Kearl main plant site currently under construction.

Not only does Imperial Oil deliver strong results, we have an asset portfolio which positions us very well for decades to come. Our proved reserves of about 3.2 billion oil equivalent barrels represent more than 35 years of production at the current level.

As Bruce mentioned, the non-proved resource base stands at about 13.3 billion oil equivalent barrels. This corresponds to over 125 years of coverage at today’s production rates, meaning a business that has prospered for more than 130 years has a long and bright future ahead. Drilling has delineated almost all of these properties, so the resource risk is minimal.

As indicated by the colour coding of the bars on the chart, the vast majority of Imperial’s opportunities are in the oil sands, shown in grey and black. Our objective for this decade is to continue to move non-proved resources to proved reserves as we continue on the path to double the size of our Upstream production by 2020.

On this chart, the bar on the left shows our 2010 Upstream production. It is comprised of about 70,000 oil equivalent barrels per day of conventional oil and gas and about 225,000 barrels per day of production from our oil sands leases - Syncrude and Cold Lake.

On the right is a projection of production by 2020. While conventional volumes are expected to decline, this will be more than offset by growth from the oil sands, most notably from Kearl, a new oil sands mining project that is expected to start-up later this year. Best in class project execution, our ongoing focus on operations excellence, and deployment of new technologies will maximize the value of these resources.

In the next couple of charts I’ll provide a more in-depth look into our oil sands capabilities and the assets.

Cold Lake is a 100 percent Imperial-owned in-situ operation. In 2011, we set a new annual production record of 160,000 barrels per day,

and a quarterly production record of 162,000 barrels per day. Despite cumulative production of well over a billion barrels, there is still a lot of undeveloped resource, and we are convinced that the best years for this field are still to come.

Cold Lake has been developed using a phased model, delivering the investment cost benefits of design one build many, while incorporating advances in technology and operating practices with each new phase. The same strategy has been used for the design of Nabiye, the next phase of Cold Lake, which was sanctioned earlier this year.

A combination of recovery-enhancing technologies and ongoing drilling will maintain Cold Lake’s base production at about 150,000 barrels per day until Nabiye production comes online in late 2014.

This chart, prepared by CanOil, tells a compelling story about reliability and our ability to consistently deliver nameplate capacity. Among all our peers, Cold Lake stands out as an operation that can deliver almost 100 percent of nameplate capacity over, in this case, a three-year period. This is the result of an outstanding resource, coupled with superior facilities design, operations, maintenance, and technology. You’ll see later that we also do this with a highly competitive cost structure.

The key takeaway here is that when Imperial describes an investment decision, such as Nabiye or Kearl, we believe that investment will deliver the highest reliability and the lowest-cost operation over the long term. The production figures we quote represent what we expect to average on a daily basis over an extended period of time, rather than a peak day capacity.

Improved understanding of the reservoir, along with the development and implementation of new technologies, have, as shown in this chart, resulted in recovery rates increasing from about 20 percent in the 1995 time frame to over 40 percent today. Looking ahead to the end of this decade, we see recovery rates in the 50 to 60 percent range.

We are currently employing two new technologies to increase recovery in late-cycle wells. The first is liquid addition to steam for enhanced recovery, which we call LASER for short, which operates by adding diluent to steam to enhance recovery. LASER has demonstrated the ability to increase oil recovered in late-cycle wells by about 35 percent.

The second technology, called Continuous Infill Steam Flood, is a process that targets the bitumen that lies between the vertical wells. Additional horizontal steam injector wells are drilled to access the bitumen between existing production wells.

The drive for innovation continues with two future recovery technologies being piloted at Cold Lake that we’ll go through in more detail a little bit later.

Cold Lake is a premiere asset in other ways. This chart from a recent FirstEnergy report shows bitumen realizations from Cold Lake compared to the range of realizations by competitors. According to this analysis by FirstEnergy, Cold Lake netbacks are consistently among the highest in industry.

Cold Lake is a low TAN bitumen and requires less diluent than some others. It is also an excellent asphalt crude, increasing its value as a feedstock to refineries.

Imperial and ExxonMobil also run Cold Lake Blend and can do so at times when the market is soft for heavy crudes, thereby providing price support.

You’ll see later on that Cold Lake operating costs are extremely competitive. When you combine high realizations, low operating costs, steadily increasing recoveries, and industry leading reliability, you have one, if not the finest, heavy oil producing asset in the world.

The investment decision to proceed in Nabiye was made in January of this year. We already started field clearing and road and bridge construction for this expansion, which is northeast of the existing Cold Lake development.

Nabiye is a continuation of our design one build many approach, largely copying the design from our most recent expansion called Mahkeses. Nabiye is expected to produce about 40,000 barrels per day starting in late 2014.

Although Nabiye received regulatory approval in 2004, we voluntarily filed a revised permit application for the Nabiye expansion. The amendments included a co-generation plant to reduce greenhouse gas intensity, the latest sulfur removal technology, and fewer well pads to reduce land use as advances in horizontal drilling technology enable reaching more of the reservoir from each pad. We received the regulatory approval in 2010. All three of these are proactive measures Imperial took to reduce the environmental footprint from the project.

Existing Cold Lake production is from the Clearwater Formation, which is about 460 metres or 1,500 feet deep. There is, however, another formation directly above the Clearwater known as the Grand Rapids. Mineral rights in the Grand Rapids Formation were obtained as part of the Cold Lake lease acquisitions in the 1960s.

However, our current ERCB or Energy Resources Conservation Board approval for Cold Lake is for production from the Clearwater Formation only. Regulatory approval will be required prior to development of the Grand Rapids.

We’ve improved our understanding of this resource over the last few years as a result of 3D seismic acquisition and a recent geological study. In addition, at least one other company has been producing from this formation for about seven years, and their experience is a useful addition to our own determinations.

Preliminary work has indicated the potential for multiple phases of 35,000 barrels per day of bitumen production development. The exact number of phases is still being studied and the best technology to apply to this formation looks like it’ll be SAGD and/or Solvent-Assisted SAGD, SA-SAGD, which is currently being piloted at Cold Lake. Our current outlook is for initial production early in the next decade.

Now let me update you on the Kearl project.

Significant progress had been made since approving the initial development in the first half of 2009. Overall, as of the end of February, we are 89 percent complete on the project, while construction progress at site is over 80 percent complete. Currently, there are more than 4,000 employees and contractors working on the project all focused on a year-end 2012 start-up.

In July 2011, the first facility at Kearl, the river water intake system, began operation. The system includes a water intake facility on the Athabasca River, which began transporting pre start-up water from the river to a temporary storage area, and which provides Kearl with the capacity to store 90 days worth of water to sustain production when water withdraws may be restricted in low-flow months.

When we shut down the river water intake system for the winter season, we had stored nearly half of the water required for start-up. As you can see in the photo, the progress on extraction, utilities, and the froth treatment facilities are well-advanced.

Workers are in the final stages of insulating tanks in the tank farms. Construction on the product shipment and diluent pipelines is progressing on schedule, and construction on the maintenance services buildings, the blue buildings in the foreground where the mine fleet will be maintained, is nearing completion.

Shown here is the ore preparation plant. This is the facility that receives the ore from the mine and turns it into a slurry mixture for transport by pipeline to the extraction plant located just over 2 miles, or about 3.5 kilometres, away at the main site.

The crusher that sizes the ore for conveyance to the slurry preparation plant has been installed in the dump pocket. The four conveyor belts have been installed, and progress at the slurry preparation plant is on track.

The initial development haul truck fleet is on site. Both electric mine shovels and a hydraulic shovel are ready for operation.

We expect to begin building the initial ore stockpile and advancing overburden removal in about three months.

Now let’s turn to the expansion project. With approval of the expansion project in December 2011, Kearl is on course to reach 345,000 barrels of bitumen per day by the end of the decade.

The initial development, at more than 88 percent complete, is progressing on schedule to commence operations by year-end 2012. Production rates are expected to be 110,000 barrels per day from the initial development.

The next step of the phased Kearl oil sands development, the expansion project, will bring on an additional 110,000 barrels per day of bitumen by late 2015. The expansion will employ our successful design

one build many approach, whereby 90 percent of the initial development engineering will be reused. As you can see in the photo, the expansion will be constructed on a site adjacent to the initial development plant site, and will leverage infrastructure investments like roads, electricity supply, camps, diluent supply, and product shipment pipelines built for the initial development. The project will also be staffed with initial development employees and contractors to capture and apply lessons learned.

With future mine and plant debottlenecking plans, which will be based upon actual operating experience, the long-term plateau volumes are expected to reach Kearl’s regulatory production limit of 345,000 barrels per day by 2020.

The Kearl lease is one of the best undeveloped deposits of mineable oil sands in the Athabasca region. The chart on the left illustrates the quality of the Kearl resource relative to other undeveloped oil sands mines in Western Canada. Ore grade and the quantity of bitumen that can produced for a given volume of mined oil sand are better than other leases.

Let me put this in perspective for you: the operator represented by the farthest left dot on the chart will have to remove approximately three 400 tonne haul trucks of overburden for every two 400 tonne haul trucks of

overburden removed at Kearl just to access the oil sands resource. The same operator will be able to produce approximately 265 barrels of bitumen from each 400 tonne haul truck of ore, whereas Kearl, with its higher grade oil sand, will be able to produce approximately 300 barrels of bitumen for each 400 tonne haul truck of ore.

Approximately half the cost of an operation like Kearl is in the mining operation, so moving material is one of the most significant factors in determining overall unit capital and operating costs. The quality of the Kearl resource will provide advantaged unit costs relative to the other new oil sands mine opportunities.

Kearl will access 4.6 billion barrels of recoverable resource, providing a long-term plateau production profile, and will be the first oil sands mining operation without an upgrader. Our proprietary Paraffinic Froth treatment technology enables us to de-couple mined oil sands bitumen production from upgrading by producing diluted bitumen that meets pipeline and refinery specifications. This technology eliminates the need for an on-site upgrader, which avoids a multi-billion dollar capital investment and its associated operating expenses.

With low-unit development costs, high resource quality, and a very long, flat production profile, Kearl is advantaged relative to traditional production profiles.

The bar chart on the right, compiled by Wood Mackenzie, shows Kearl’s revenue components. We expect Kearl to be one of the lowest unit cost oil sands mining projects in the industry, and to provide attractive returns over the long term. And we’ll see one of the major reasons on the next chart.

As a starting point, historical oil sands material handling system availability has been on average about 65 percent. Our project team analyzed historical operating data to identify the most significant contributors to downtime. Not surprisingly, the most significant contributors to unplanned downtime were found in high-wear areas of the material handling system. Engineering studies identified several cost-efficient design and operability enhancements that were incorporated into the Kearl design to provide a 12 percent planned improvement in system availability.

Some of these enhancements include: dual hydro transport lines, which will typically operate at about 60 utilization, so that when unplanned or planned maintenance occurs on one of the lines, the impacted line can

be taken out of service while utilization on the remaining line can be increased to make up for the shortfall; twin tailings lines on the extraction system to permit continuous operation while one line is down for scheduled maintenance; and improved crusher and conveyor operations to optimize maintenance intervals to maintain target level of availability.

We’ve also made enhancements to the process side of the operation. These include additional bitumen line heat tracing for flow assurance, facility enhancements to our electrical supply system to mitigate the potential for grid power outages, and restart capabilities following a power outage.

We’ve also identified future debottlenecking opportunities (additional Ore Preparation and Extraction Plants) that we plan to implement within the first five years of operation that will also increase both capacity and system availability by a further 13 percent to a total of about 90 percent.

We have extensive lease holdings in the Athabasca area, totalling about 250,000 acres. These are poised to be the next generation of mining and in-situ developments with production contributions starting sometime around 2020. We have continued to refine our understanding of these assets with extensive seismic and drilling programs.

Foremost among these holdings is a property about 35 kilometres south of Kearl which we call Aspen. It is 100 percent Imperial owned and has a high-quality resource most amenable to recovery using SAGD. We believe the lease will support an 80,000 barrel per day operation ready for first production by the end of this decade following a successful regulatory application.

Now I’ll talk about Syncrude. Imperial utilizes a comprehensive set of systems, developed and applied worldwide by ExxonMobil to manage the many risks that we face. These are being introduced into Syncrude to build a solid foundation for the future.

The Controlled Integrity Management System, or CIMS, provides a structured process for conducting business in a well-controlled manner. This includes establishing effective controls, monitoring and enforcing compliance continuously, and resolving control weaknesses in a timely manner.

Recognized as a model of success in the industry, the Operations Integrity Management System, or OIMS, provides a robust framework for managing safety, security, health, and environment risks. OIMS enables us to measure progress, ensure management accountability for results, and establishes common expectations for controlling operational risks.

The ExxonMobil Capital Project Management System, EMCAPS, uses management gate reviews, checkpoints, and processes to ensure projects are delivered in a safe and environmentally responsible manner, deliver assets of appropriate quality, meet cost and schedule expectations, and achieve commercial success.

The Global Reliability System, or GRS, is employed to prevent high-impact equipment and facility failures and to improve equipment reliability. The benefits can be significant, and have resulted in material reductions to unscheduled downtime around the world at other locations. This is the area that requires the most patience and work to achieve results.

Reliability is complex - a function of design, operations, and maintenance. Syncrude has demonstrated high rates of throughput for short periods of time so the hydraulic design appears adequate. However, each piece of equipment also has to be able to sustain the stress of operations for extended periods of time, and that relies on other aspects of design, like original material selection, mechanical integrity, durability, and so forth. The operating limitations of the equipment also need to be well-understood and translated into envelopes that must be adhered to by process operators.

Process upsets from power failures and equipment malfunctions need to be properly handled to avoid equipment damage. Also, preventative maintenance, equipment monitoring, and root cause failure analysis all need to be part of an overall effective maintenance program. All of these - design, operations, and maintenance - are also a function of properly trained and educated staff, adequate equipment, and ongoing managing systems that tie it all together. A major limitation to rapid progress is that equipment issues can only be properly addressed at turnarounds, which are relatively infrequent.

GRS, the Global Reliability System being introduced at Syncrude, is designed to address all of the items I’ve been discussing. But in an operation the size of Syncrude with as many pieces of equipment that require design assessment, maintenance strategies defined, operating envelopes developed, and workforce training to effectively execute, it takes time to achieve progress.

We’re not satisfied where we are and we are determined to do better.

Together with ExxonMobil on a 50/50 basis, we have acquired a significant acreage position in the Horn River Basin totalling over 340,000 acres. About half of this acreage was acquired in 2009, when prices were low and many of our competitors had financing concerns, and we continued to expand our position in 2010.

Field work in now underway at one of our Horn River leases on a production pilot. We drilled an eight-well pad, which we expect to start producing later this year at about 30 million cubic feet per day. The purpose of the pilot is to further understand productivity, but more importantly to understand and work on the cost structure of drilling and completing in the Horn River Basin.

A full-field development in Horn River will involve thousands of wells, and the key to developing a premiere asset is to be the low-cost operator. To assist with the production pilot design, we’ve engaged ExxonMobil’s XTO organization and are bringing their expertise to bear on the development of this resource. Once we’ve gained the valuable understanding from this pilot, we will be able to start planning for a full-field development, which could occur as early as late this decade.

At this point we’ve scheduled about a 15-minute break, after which Bruce is going to take you through some elements of our leading-edge technology.

So we’ll break now until about 10:35.

JOHN CHARLTON: Feel free to refresh your coffee or whatever you’d like and we’ll get right back together.

BRUCE MARCH: As we are re-assembling here in Toronto, I would like to note that for those of you who have dialed in through the webcast, feel free to send in any questions you may have for our upcoming Q&A period.

We’ll restart now and talk about technology leadership and just start out with this cover slide. Over our long history, Imperial Oil has been a real pioneer in Canadian energy. We recognize that meeting the world’s growing energy needs will require technology breakthroughs to unlock energy resources and shareholder value, and that’s certainly true for Canada’s oil sands.

We own and operate the world’s largest heavy oil in-situ operation at Cold Lake, and believe it or not, those leases were acquired by Imperial Oil way back in the 1950s. We’re a founding member of Syncrude, the world’s largest oil sands mining and upgrading facility, and Imperial’s Kearl project will be another technology breakthrough. We’ll be the first mining project to market bitumen directly without an upgrader.

All projects we do are underpinned by technology leadership. For half a century, we have employed and challenged a cadre of scientists and

engineers at our own research centre in Calgary. These scientists and engineers collaborate with leading academics, and participate in joint-industry research too. These are employees with a mission, and that mission is to advance upstream technology which will improve financial results.

The two photographs on this slide were taken at our research centre in Calgary. On the left is what we call a physical model experiment. Here, a researcher can create a physical model of different oil sands content and different oil sands recovery processes. On the right is another vessel that creates reservoir conditions of certain temperatures and pressures, into which the physical model is inserted. This is a very sophisticated and unique scientific apparatus that we use to explore different in-situ technologies.

Imperial has a shared research agreement with ExxonMobil that provides two-way access to the results of about $1 billion of annual combined research. Together with ExxonMobil, we have conducted more than 2,000 work years of scientific research in heavy oil production.

The top of this page shows only part of a pipeline of technologies resulting from this heavy oil research. Imperial invented and patented the two most successful commercial in-situ recovery technologies, the Cyclic

Steam Stimulation or CSS, that we use at Cold Lake today, and Steam Assisted Gravity Drainage or SAGD. We’ve developed processes for recycling produced water, imaging production zones, and enhancing recovery.

The flow of technologies from the laboratory to the field has made Cold Lake the premier in-situ oil sands operation in the world and we intend to do the same for Kearl.

Last year, our researchers added another 17 patents, most of them in the oil sands area, and that’s in addition to a long, long history of achievements. We’re pursuing some new processes that could eliminate the need for water, eliminate the need for steam in in-situ operations, and for water in oil sands mining. I’ll talk more about these potential technology breakthroughs in the charts that follow.

The first of two new in-situ technologies is called Solvent-Assisted SAGD or SA-SAGD. Our research has shown that by mixing a low concentration of solvent with steam, it can enhance bitumen recovery in in-situ operations and reduce greenhouse gas emissions intensity. The picture on the left of this chart is of the SA-SAGD Cold Lake pilot facility, which we put into operation in 2010.

In the second technology, we are taking SA-SAGD a step further by testing a recovery process using only a hydrocarbon solvent. We call this Cyclic Solvent Process or CSP and if successful, both water use and greenhouse gas emissions could be nearly eliminated where CSP is applied to in-situ operations. We conducted a successful field trial of CSP in 2009 through 2011, and a pilot consisting of three horizontal wells was sanctioned late last year. We expect to start the pilot up in late 2013.

In the area of oil sands mining, our Kearl project will be the first to produce saleable diluted bitumen without an upgrader. This saves capital, operating costs, and improves the long-term asset reliability of Kearl. Most of the reliability issues associated with oil sands operations are with the upgraders - we know this very well from our experience with Syncrude.

This is only possible because of a new proprietary technology called High Temperature Paraffinic Froth Treatment or another acronym, HT-PFT. This technology was developed internally by Imperial and ExxonMobil and patented in 2007. The graphic in the lower half of this page shows how HT-PFT works.

The traditional froth treatment technology for mining operations is known as naphthenic froth treatment. The result, which you can see on the bottom, is a product that can be as high as 3.5 percent basic sediment

and water. This far exceeds the fungible pipeline specifications of 300 ppm BS&W for saleable crude oil. Using naphthenic froth treatment, this product has to be upgraded on site or transported in a proprietary pipeline to some form of an upgrader or refinery.

The HT-PFT technology selectively separates asphaltenes. Asphaltenes are the very lowest value component of the bitumen barrel. These asphaltenes also happen to carry most of the very fine solid material, and we return these asphaltenes to the mine. When combined with diluent, the High Temperature Paraffinic Froth Treatment product has less than 300 ppm BS&W, and can be shipped by common industry pipeline systems. The asphaltenes and the associated BS&W represent about 8 percent of the mined bitumen, as you can see on this chart.

Now because HT-PFT removes the heaviest asphaltenes, our Kearl bitumen will be somewhat lighter than the other marketed diluted bitumens produced in the oil sands. We expect that Kearl diluted bitumen will achieve similar prices as we get further bitumen in our Cold Lake operations.

If you’re wondering about the asphaltenes that are returned to the mine, it’s interesting to point out that when using naphthenic froth treatment and an upgrader, the asphaltenes are almost entirely converted to petroleum coke. And that petroleum coke is normally returned to the mine anyway.

Fluid tailings represent a significant challenge in oil sands mining operations. The legacy mining operations of Syncrude and Suncor have both built a very large tailings legacy and a significant environmental footprint. Our research in tailings management is focused on how to deliver a solution that meets the environmental regulatory requirements faster and at a lower cost.

Fluid tailings are generated from the water-based extraction process. After mining the oil sands ore, hot water is added together with air to separate the bitumen from the solids and to float the bitumen to the surface for collection in what we call a primary separation vessel. The solids, composed of course sand and very fine particles, go with the water to the tailings pond. This mixture of fine tailings with water forms a yogurt-like mixture that nature takes decades to separate.

We have, however, found ways to chemically glue the tailings particles together with a substance called an in-line flocculent so that these very fine solids separate from the liquid very quickly. We call this process CIMA or Chemically Induced Micro Agglomeration. And the entire process can be made to occur within a continuous length of pipe.

The graphic at the bottom of this chart shows fresh tailings becoming agglomerated tailings after the addition of the flocculent. The resultant dry tailings deposit sits at the outlet of the pipe to the right. This picture of the flotation tailings deposit is after a few days of drying, and you can see that the deposited material is strong enough to be used directly for reclamation, and the water that we separated earlier - clean enough to recycle and reuse.

We’re currently in the process of securing a site for a field trial of CIMA next year. An important difference for our Kearl project is that after a few years of initial mining and a few years of the use of a tailings pond, we will treat our tailings streams as they are produced. And we will significantly minimize the size of the Kearl tailings pond, and all the associated reclamation costs that come with that.

Non-Aqueous Extraction or NAE is being actively pursued at our Calgary research centre. Shown here in these pictures, the naturally occurring oil sands on the left will be selectively separated with an organic solvent instead of forcefully separated with hot water in the current bitumen extraction process. The solid sand and clay agglomerates are left behind for prompt placement back into the mine as dry tailings. After solvent is separated from the bitumen, it is reused in this selective extraction

process. This new technology works successfully at the laboratory bench scale. The next step is to increase the scale of the technology in a pilot plant, and eventually continue this scale-up to a commercial pilot level.

This NAE technology would be a huge breakthrough from a number of perspectives: for example, energy costs would be much lower because the need for hot water would be largely eliminated. And it would eliminate the need for fluid tailings ponds altogether. Capital and operating costs would also be reduced, and, as you can see, the environmental performance overall would be greatly enhanced. This is only one example of our company’s focus on responsible development of Canada’s oil sands, and how the ongoing use of technology to develop one of the world’s largest recoverable energy resources is being developed.

Now in our view, the very best solution in oil sands mining is to not create a tailings pond at all. The volumes of tailings created from mining operations can be quite large, and each time the material has to be handled is an expensive step and adds to your operating costs. The CIMA process is designed for this purpose, but since it’s not yet commercially available, we have to explore other alternatives as well. The Province of Alberta has a directive called Directive 74 requiring tailings to be remediated quicker than that decade-long natural settling process would

provide. There are four technologies currently available that could be employed to meet Alberta’s Directive 74. Operators’ choices will depend on many factors, some of which are outlined in this matrix chart. It will also depend on whether you’re dealing with existing tailings, like Syncrude or Suncor, or in the case of Kearl, future tailings.

The matrix on this chart illustrates the four technologies and their relative merits across five different dimensions. Those dimensions are: capital cost, operating costs, chemical cost or usage, material handling, and the space required with these different technologies.

Now we have only recently settled on the technology to be employed at Kearl. In the news release for the Kearl expansion project in December, we pointed out that part of the higher costs for Kearl were attributable to these decisions around tailings management. This is because Imperial has chosen to use tailings thickener technology shown at the bottom of this matrix. This technology has a somewhat higher initial capital cost, but over the life of the mine will result in lower operating costs, chemical usage, and material handling costs, and will sterilize less of the oil sands resource.

Now another key, exciting area is how the industry is working together to improve the environmental performance of the oil sands. In

2010, Imperial was one of the companies that formed an innovative research collaborative to advance the management of tailings strategies. The companies agreed to share existing technologies and pool research development going forward to improve the pace of oil sands tailings reclamation.

This approach has since been extended through the creation of COSIA. COSIA stands for Canada’s Oil Sands Innovation Alliance. The Alliance’s vision is to enable responsible and sustainable growth of Canada’s oil sands, while delivering accelerated improvement in environmental performance through that collaborative action and innovation.

Our capability to access and implement innovative technology is essential to meet the growing energy needs in a responsible manner. And we believe industry collaboration should accelerate progress towards an improved overall environmental performance.

COSIA currently includes 12 companies that represent over 80 percent of the oil sands production in Canada. Our approach will bring multiple companies together to share intellectual property related to four environmental priority areas. This intellectual property will be used in a manner that continues to value and continues to protect corporate

technologies, but still provides for access for other companies which can apply and build on these technologies to improve their environmental performance.

Now we’ll shift gears here for a minute, and for today’s investor conference we did not plan to do a complete review of our Downstream and Chemical business. However, I thought it would be appropriate to spend a few minutes to discuss the impact that new upstream production in North America is having on the Downstream and Chemical businesses, and most importantly, share with you our thoughts on how being an integrated energy company will continue to be very rewarding.

Developments in the upstream create opportunities and they also create challenges. Energy is one of our largest expenses in the Downstream and Chemicals business. And low North America natural gas prices are advantageous, particularly when you combine them with cogen facilities that we have in our Sarnia refinery, and will build at Kearl and Cold Lake.

North American market-based prices for natural gas versus Asian crude-based prices will also provide arbitrage opportunities in the future, most likely for LNG first.

The flip side of a low natural gas price in the downstream is its’ potential to be used as a transportation fuel, and the potential impact it could have on gasoline and diesel demand. We do see some expansion of the use of natural gas in vehicles, but primarily in local or regional truck fleets that re-fuel at a central location. Incremental costs and driving distance limitations will likely keep penetration of natural gas in vehicles at a low level - particularly for personal and heavy-duty vehicles.

Our Sarnia Chemical facility is completely integrated with our Sarnia refinery operations and is within a day’s drive of over one-half the polyethylene demand in the United States. But dwindling supplies of advantaged polyethylene feedstock have been a challenge recently. Last year, Imperial announced that it had entered into a long-term supply agreement for ethane from the Marcellus shale gas development area. This competitive supply from nearby shale gas will provide a significant advantage to continue profitable ethylene operations at our Sarnia chemical plant.

I would expect a challenging business environment will continue for the downstream businesses in North America. Overall, this view reflects a global increase in industry refining capacity, most notably in the Middle East, India and Asia. But it will also put pressure on developed companies that have an overall flat or declining demand profile.

Different dynamics, however, are affecting the North American in-land refineries. By 2020, tight oil production will likely represent the largest source of North American domestic crude production. Today, increased supply of light sweet crude from these plays is exceeding pipeline outflow capacities. This bottleneck has contributed to volatile WTI-Brent differentials, which has reduced realizations for upstream producers. However, on the flip side, the same volatile WTI-Brent differential have resulted in the refineries in the Mid-continent of North America benefitting from a lower crude cost - which includes our facilities at Strathcona, at Sarnia, and to a lesser extent, Nanticoke. Refining utilization in the regions with advantaged feedstock prices is very high.

Similarly, Western Canadian bitumen production is also increasing. In the near term, sufficient pipeline capacity exists to move bitumen into the expanded conversion of several PADD 2 refineries. An opportunity exists for Canadian bitumen to fill the deep conversion refineries on the US Gulf Coast, but new pipeline infrastructure is required to meet this demand for heavy crude.

Imperial and ExxonMobil’s downstream personnel are working to enhance the evaluation and the marketing of our new Kearl bitumen. Our refining technology tool kit is being employed to understand the characteristics of Kearl diluted bitumen, and how to maximize its’ value at our refining sites. Not all the production from Kearl will go to our equity refineries, a good portion will go to third parties. Our supply organization has a broad understanding of the marketing options for this new Kearl crude.

Many times, it takes a while before the true value of a ‘new crude to market’ is realized. Should this occur, we have a large and flexible refining and logistics network that will be able to provide backstop processing capabilities and capture this value ourselves.

The second issue is pipeline infrastructure. We have the logistics plan in place now to handle the Kearl Initial Development volume, which we’ll start producing later this year. So we’re not dependent on new take-away capacity from Alberta for Kearl Initial Development volumes. However, new capacity is required by about 2015 or 2016 when the Kearl expansion project will start-up.

As you can see on this map, there are several alternatives being worked by the energy industry. We believe that the merits of the Keystone

XL project will prevail above the current political issues, and we believe it will get approved and built. Beyond Keystone XL, there are other proposals being advanced that will increase the takeaway capacity from Alberta even further and improve the market diversification for Canadian crude oils.

Let me now introduce Paul Masschelin. Paul’s our Senior Vice-President for Finance and Administration and our company Treasurer. Paul’s going to take you through a more detailed look at our financial performance.

PAUL MASSCHELIN (Senior Vice-President, Finance and Administration, and Treasurer, Imperial Oil Limited): Thank you, Bruce. As mentioned earlier, Imperial Oil had its second best year of earnings in 2011, with net income of almost $3.4 billion or $3.95 per share.

As you can see from the chart, return on capital employed was just over 25 percent. That’s notwithstanding that we had in excess of $7 billion of assets under construction on our balance sheet at year-end, which, of course, are not yet contributing to earnings. Excluding these assets, return on capital employed would have been about 60 percent.

Also as you can see, Imperial generated sufficient cash to fund the sizeable investment program for the year, and as such, we finished 2011 with a debt to capital ratio of 9 percent and zero net debt.

I’ll now briefly look at the financial performance of the individual business segments, starting with the Upstream.

The Upstream strategy of doubling production by 2020 continued in 2011 with about $3.9 billion invested, while at the same time generating about $2.5 billion of earnings. Return on capital employed for the Upstream business was 22 percent, again notwithstanding the very large assets under construction on the balance sheet. Despite the very significant investment program we had underway, the base business continued to perform very well with total production just under 300,000 oil equivalent barrels per day, including record production at Cold Lake of 160,000 barrels per day. And as you know, Imperial’s production is heavily weighted towards liquids, most of it from oil sands.

I’d like to say a few words about the Downstream and Chemicals businesses. These businesses operate in very mature markets and as such, our strategy is to leverage the asset base by maintaining best-in-class unit costs and driving for sustained high reliability.

Capital investment in these businesses is being kept at or below depreciation. As you can see during 2011, our downstream business earned just under $0.9 billion and produced a return on capital employed of 29 percent. Refining throughput of 430,000 barrels per day yielded about 85% utilization of our refining capacity. Capital expenditures were $166 million, which is equivalent to about three-quarters of our depreciation for the year. These investments were focused on reliability, improving environmental and safety performance, as well as continuing to upgrade our retail network.

As you know - and as Bruce already mentioned - in 2011 three of our four refineries benefited from the large difference between WTI and Brent. Three of our four refineries have cost of goods sold driven from WTI-based crude pricing and product pricing based on the adjacent US markets - which are predominantly priced off Brent. As such, we saw healthy downstream refining margins that underscored the benefit of being an integrated oil and gas company.

Let’s shift to the chemicals business briefly. Our strategy here is to continuously reduce unit costs and maximize value by further integrating the Chemicals business and the refining business - while at the same time obtaining advantaged feedstock. As Bruce mentioned, last year we signed

an agreement giving us access to Marcellus Shale ethane, which will be a very advantaged feedstock for our cracker in Sarnia. We will start taking delivery on that contract next year.

As you can see on the chart, earnings in the Chemicals business of $122 million last year were up more than $50 million versus 2010. The main reason is we had significantly less planned maintenance in 2011 versus 2010. Also, we saw improved margins in intermediates and aromatics and were able to sell larger polyethylene volumes. Overall, return on capital employed in the chemicals business was 59 percent.

As both Glenn and Bruce have mentioned, achieving and maintaining a sustainable unit cost advantage is integral to our strategies. This chart from FirstEnergy shows how Cold Lake operating costs compare to a range of operating costs from other in-situ oil sands operators. A couple points are worth highlighting here. First, costs are generally lower for new in-situ operations, as the best part of the resource is developed first and the oil closest to the initial wells is produced. Many of the competitors shown on this chart are indeed in that stage of the life of their development. Yet if we think about Cold Lake with over 25 years of commercial operations, you can see it continues to be among the lowest cost in-situ operators. That is being delivered through detailed operating experience, phased development, in-depth knowledge of the reservoir, and the continuous application of new technology.

Operations excellence, which we’ve talked about before, also requires disciplined preventative maintenance. As you can see on the chart, this year - and more precisely in the next quarter of this year - we will see more than the average turnaround activity in our operations. Both the Strathcona and Sarnia refineries will undergo significant turnarounds. In the upstream, one of the Syncrude cokers will undergo extended maintenance, as will our Mahkeses plant at Cold Lake.

As was highlighted on an earlier chart, Imperial creates value for its’ shareholders three ways: through dividends, through capital appreciation, and through stock buybacks. We have paid dividends uninterrupted for more than 110 years, and as you can see on the chart per share dividend payments have increased every year for the past 18 years.

If you focus in on the period 2006 till now, per share dividends are up 50 percent. Over the time period shown on this chart, we have returned $5.7 billion to the shareholders through dividends. Although, of course, our Board of Directors sets our dividend policy on a quarterly basis, what we’ve shown here for 2012 on the chart is the current dividend, which was

increased recently, continuing for the remainder of 2012. Our policy with regards to dividends is simple: they continue uninterrupted and they increase as the base cash flow increases.

Both our financial strength and our flexibility underpin the confidence which we have in the upstream growth plans which Glenn covered. In other words, we have the capability to pursue the strategy which we have set out uninterrupted and irrespective of the business cycles.

We continue to be the only Canadian industrial which has a AAA credit rating. Also, the strength of our balance sheet and the strength of our businesses permit us to shoulder the significant step-up in capital expenditures during this decade, which we expect between 2010 and 2020 to be between 35 and $40 billion; most of that to double upstream production by the end of the decade.

Also, we have a history of significant share buybacks, and as you can see on this chart, between 1995 and 2009, Imperial repurchased more than 50 percent of its shares, and returned $15.5 billion to its shareholders. We suspended our share purchases in 2009 to redirect cash for the growth investments we talked about. Since 2009, our share buybacks are limited to those for anti-dilutive purposes.

This chart, and the last one which I will cover, gives you a perspective of the resilience of our growth strategy. As you can see, over a wide range of crude oil prices we have the ability to finance our investment plans, while maintaining a conservative debt-to-capital ratio.

Indeed, if the current crude prices were to persist, Imperial could be debt free and generating free cash flow by the middle of this decade. In a more conservative scenario of about $70 per barrel WTI, we would see our debt to capital ratio peak briefly at about 30 percent and then rapidly decline to be debt free by the end of this decade.

So with that, let me turn the podium back to Bruce.

BRUCE MARCH: Thanks, Paul. Well, I hope that you’ve just seen that we have a very long history of delivering shareholder value.

We face the future with confidence that our company’s strengths will continue to deliver that very same strong shareholder value. And I hope you can appreciate our primary focus is to maximize shareholder return over the long term, and to do so at a rate that’s greater than our competitors and the broader market.

As I said earlier, I’m proud of our operating and our financial performance and the competitive advantage that we continue to capture. Our existing portfolio of assets is very high performing and the quality of

our resource base enables sizeable and profitable volume additions. We have access to ExxonMobil’s global resources to execute our upstream growth strategy and to double our current production by 2020.

I believe we have a unique level of discipline and consistency in the management of our business that has proven over time to deliver superior results. And while others have taken steps to abandon the integrated business model, we conclude that our ability to implement value capture across the integration of our business is a competitive advantage.

Underpinning these strengths is our superior technology and outstanding financial strength, allowing us to take advantage of conditions across the whole business cycle. And finally, we operate in a country where private investment is welcome and supported by both the Governments of Alberta and the federal Canadian government.

This concludes our prepared remarks for this morning, and Glenn, Paul, and I would be happy now to answer any questions that you may have.

For those of you that joining us on the webcast, please feel free to send your questions forward. Linda and Christine have microphones, and so please tell us your name and then go ahead and ask your question.

PETER OGDEN: Good morning. Peter Ogden with Bank of America Merrill Lynch. Can you just quickly maybe elaborate on your marketing arrangements for Kearl? I know you mentioned some is going to equity refineries and some is going to third party. Exactly how much? Those equity refineries, does that back out additional heavy oil into the market that they’re currently using and then what impact do you see? How exactly is 110,000 barrels a day going to be absorbed by the broader market? And the second part of that question, I guess, what’s the current bottleneck on Kearl in getting it on-stream by Q4?

BRUCE MARCH: Okay. Those are two meaty questions. I’ll put this chart back up. Everything we talk about at Kearl is in bitumen barrels; the 110 that we’ll start-up later this year will translate to about 140 to 145 thousand barrels per day of diluted bitumen.

We’re not depending on any new pipeline systems for the Kearl initial development volume. In fact, they won’t be in place when we start-up later this year. In blue is the Enbridge mainline system which supplies the Upper Midwest, as well as the location of our refineries in Edmonton Nanticoke and Sarnia.

Today, we produce about 250,000 barrels a day of crude oil, but we refine about 430 to 450. Already we’re buying crude oil from the market, and we make those crude oil decisions based on the assets we have and the most value that we can generate from those assets.

Kearl Initial Development will produce the first diluted bitumen from a mining operation without an upgrader. We have experience around the world indicating that a new crude-to-market typically has some questions. Using our refining tool kit, our researchers and engineers have done a lot of work to really understand the challenges of running a diluted bitumen, like Kearl, in a refinery today. The challenges are primarily in the desalting area and we have a really good handle on that.

As Kearl starts up, I would expect that we’ll run a fair amount in our own refining system, which I should say includes ExxonMobil’s Billings plant, which is tied into the Express pipeline. The real workhorse that ExxonMobil has in the Midwest is in Joliet just south of Chicago. Joliet is about 240,000 barrels a day. They run a lot of Cold Lake today and it is a real workhorse for heavy sour Canadian crudes.

We’ll continue to make economic decisions based on third party interest. There are four big refineries in the Midwest, not ours, but BP in Whiting, Marathon in Detroit, ConocoPhillips down farther south in the Wood River that Cenovus has an interest in, and there’s a fourth that I’m forgetting, apologize. All of them are going through a large expansion of

their ability to run heavy sour Canadian crudes. Most of those investments are either complete or very well along, so we expect that they’ll finish them. We’re working with those companies today to ascertain their interest in running volume from Kearl initial development.

I can’t tell you, Peter, exactly what we’re going to do. We’re going to make economic, market-based decisions on how we fill our refining system. What I would say is between the two ExxonMobil facilities and our three Imperial refineries, we’ll have the ability to run just about all of the Kearl initial development, if we choose to.

What comes next by 2015 is that some new pipeline systems are built - Keystone XL, and the Enbridge system from Flanagan, Illinois through Cushing and onto the Gulf Coast. The oil sands are opened up tremendously post-2015 with these expansions.

We support and eventually expect Northern Gateway to go to the Western Canadian coast and open up Asian and West Coast markets in the United States. We need all these expansions of the takeaway systems in Alberta to support future growth.

I also mentioned briefly about the opportunities and challenge that has come with all the crude that’s being produced in the Bakken, as well as the Niobrara in the centre Colorado area, and then finally, the Eagle Ford. This is one of the elements putting a lot of pressure on WTI and its’ value versus Brent - which is much more fungible due to its’ waterborne delivery.

I think it’s fair to say the industry has under-predicted the growth of these tight oil crude opportunities; they have contributed quite a bit, along with the Canadian oil sands growth, to this WTI-Brent volatility. But it’s a little hard to predict how fast it will grow, what markets it will seek, and where it goes moving forward.

Pete, I’m going to have to ask you your second part of your question.

PETER OGDEN: Bottleneck at Kearl.

BRUCE MARCH: Bottleneck at Kearl. Okay. We continue to work very, very hard on the 200 full-size modules that we had built in Korea. I think all of you are familiar with it. We’re making good progress. Just as a brief background, we have about 1,200 equipment modules. Everything we’re doing at Kearl is modular with very little being built at the Kearl site; most is built outside of Kearl and then transported to the site in a modular development. There’s an obvious cost efficiency in doing it that way compared to what you can do up north of Fort McMurray.

We needed about 1,200 modules or equipment skids to complete the Kearl initial development, and 1,000 of those were built in the Edmonton area, or other parts of Canada, and delivered on time, on budget; very good performance.

At the time when we sanctioned Kearl in late 2008, early 2009, we couldn’t confirm that there would be space in Edmonton or elsewhere in Canada to construct 200 of the modules. Most of these 200 modules were associated with the ore preparation plant and some with the froth treatment area. A lot of the equipment for these modules was won in a competitive bid by a Korean company. That equipment could have come in pieces and then been assembled in Edmonton. When we couldn’t procure yard space to do that, we decided instead to have the original equipment manufacturer in Korea build the modules - they are very experienced doing that.

As we speak today, we’ve got about 75 of the 200 at the Kearl site, either shipped directly or broken apart, transported on the US Interstate Highway System and then reassembled at Edmonton and transported to Kearl.

We’ve got about another 75 modules either in assembly or waiting to be reassembled. There is a workforce of about 1,000 people in three Edmonton yards working hard to put these modules together. The original port of Lewiston, Idaho has been emptied - there are no more modules there. We have about 40 or so modules in Pasco, Washington - which is a smaller port not too far from Vancouver, Washington - that have been yet to be transported to Edmonton for reassembly.

Our goal is to get all these modules to Edmonton and in the reassembly chain by about early May, and we’ve identified where each and every module is on the critical path for start-up to occur by year-end. First on the critical path is the utility section; we need to start-up the boilers to make hot water and to circulate hot water out to the ore preparation plant before the weather gets too cold. Thereafter, it’s kind of an orderly start-up of each and every system - the extraction plant, the ore preparation plant and then finally, the froth treatment plant. So that’s the nature of our challenge.

We’re very confident that we’ve got the capability to meet year-end. That’s certainly our goal and we’re absolutely committed to that. But it’s really about getting the utilities modules reassembled and deployed at the Kearl site, buttoned together, followed up by froth treatment, followed up by whatever else is left. And that’s where we stand today.

Yes, George?

GEORGE TORIOLA: George Toriola from UBS. A two-part question for you; the first is when you say start-up by year-end, what does that actually mean? When do you export bitumen precisely? And then the

second part is around capital costs. So when we look at the costs for phase I and II that you’ve talked about, it’s substantially higher than what the rest of industry has done, and the rest of industry’s also suggested that those costs are not in line with what they plan to do. So if you can talk about what it is that you are doing? And how you would be competitive from here on in terms of capital ?

BRUCE MARCH: Good questions, George. Start-up to us is making a finished product. That’s what we mean by start-up. Start-up means that shovels and trucks are working, ore is going through the preparation plant, we’re separating out the solids and doing the final froth treatment; we’re getting all the fine solids out and making oil that’s less than 300 ppm BS&W (basic sediment and water) .

If you look at the pictures of Kearl very carefully, there’s not a lot of tankage at Kearl; a couple of finished shipping tanks. We do have more storage down in the Edmonton/Hardisty area where we enter the Enbridge system, but there won’t be much of a shipping delay. Pretty much what we make goes out.

To your question about economics, I can’t comment on what any other competitor is looking at and I wish they wouldn’t comment about what we’re doing, to be honest with you. At the end of the day, you can pull up cost curves reflecting total erected costs, and see that cost growth is relentless. I think all of you know that.

We made a really good decision back in 2008/2009 to stay with Kearl. Our competitiors took all their big stuff and a lot of their smaller projects, put a ribbon around them or a Do Not Enter sign, and stopped for a couple of years. We plowed ahead and got a great set of project contractor partners and we’re happy by and large with their performance. We have a very productive workforce. With the expansion phase we’ve tried to sanction it in such a way that we can roll that workforce over. Labour is getting short, particularly experienced labour in the oil sands. So we just take the contractors finishing KID (Kearl Initial Development) along with our own project team and operating workforces, and roll them right into KEP (Kearl Expansion Project) and start to build that.

We would always like project costs to be lower than they are, but we’re pleased with where we’re going to end up. We think we’ve got a competitive, very long term 40-year life project in Kearl that will recover our cost of capital and give us a bit more.

We’ll have to see where the other competitors come out, George. I’m just as anxious as you may be to see where they go. I think the next big oil sands mining upgrader facility is likely a year plus away and I would say let’s make our judgements then rather than now.

Yes. Mike, how are you?

MIKE DUNN: Good, Bruce. Thanks. Mike Dunn with FirstEnergy. A couple of questions, Bruce, for you. You’ve mentioned today three of your four refineries are benefiting from the discounted crudes. Just wondering where Dartmouth sits in terms of your longer-term plans? Imperial Oil itself does not own any East Coast offshore projects, although Exxon obviously does, except for Sable…

BRUCE MARCH: Yes…

MIKE DUNN: But where do you see that? Is it something longer term that’s maybe strategic with Hebron…coming in with heavy oil supplies? Or presumably that’s the money loser of the downstream business for you right now. And then secondly, I think briefly in your slides you mentioned looking at the LNG market for Horn River. I haven’t heard you or Exxon talk about getting involved in terms of LNG projects in Western Canada, so maybe some comments on that?

BRUCE MARCH: Okay. For Dartmouth, first of all, it sits in a very, very tough basin. You’ve read the announcements on what Sunoco is doing, what Conoco is doing, what others are looking at, what Hovensa is

doing in the Caribbean. It’s just a very tough basin; same thing in Western Europe with a lot of capacity being shuttered. The economies aren’t performing well, and there is low demand for transportation products.

We look at the economics of our refining systems - in fact, our whole downstream business as well as our upstream and make sure that they’re high performers. These aren’t easy decisions. We monitor and steward it very aggressively all the time. Nothing specific to tell you about Dartmouth today; you can do the numbers and you’ll see it is economically challenged, no question about it. So I would just say that we look at it all the time and make decisions based on what we see going forward.

A specific new development, Hebron, that ExxonMobil has, is going to produce a crude oil that’s a Brent pricing basis, so I don’t see that as a key fundamental. That crude is going to flow into the greater Atlantic basin market and compete with everything else.

LNG. I think at ExxonMobil’s Investor Day a couple weeks ago some of you may have listened to the discussion about that. ExxonMobil commented that they are looking at LNG opportunities all across North America. That would include the States and Western Canada.

In particular, natural gas - different from oil - continues to have a stranded nature to it and LNG has helped with that in some markets. In

North America today, with the supply/demand balance and prices, it’s obvious that in Western Canada, in particular, it is stranded. So we’re looking at those opportunities.

These are big, fundamentally complex challenges, though. ExxonMobil is looking at it for Western Canada and we’re working with them to ascertain questions like: What is the resource? How will it be developed? What does it cost to develop? How will you continue to develop that resource for 25 or 30 years? Where’s the biggest value? I will tell you that LNG with shale gas is a lot different than LNG with conventional gas. We’re working through that, studying it very, carefully and taking our time. There’s a lot of interest, a lot of activity. That fits your follow on question. I think those companies are likely doing the same thing.

Our majority shareholder is involved with an equity stake in about a third of the LNG in the world today, so they’re a major player. They’ve got great expertise so I’m thrilled that they’re our partner on wherever we go. We’re active and looking at it, but nothing more specific to share with you at this time.

MARK POLAK: Mark Polak with Scotia Bank. You mentioned in one of your earlier slides acquiring acreage in Northwest Territories for

shale gas and tight oil in Alberta last year. Just wondered if you could provide a bit more detail how that 250,000 acres is split between those two? And on the Northwest Territory side, what are the plans there in terms of assessing the quality of that resource and what’s the earliest we might see production?

BRUCE MARCH: I’m going to ask Glenn to handle this question.

GLENN SCOTT: Most of the acreage that we did acquire last year was in the Central Mackenzie Valley in Northwest Territories under a federal land sale that took place. Under the provisions there, we need to do some drilling within the first five years of a nine-year primary term, and then establish some deliverables. If you can produce natural gas or oil to surface then you can convert the lease and hold it. We had been studying that opportunity for quite some time, and fortunately were well-positioned to bid on the acreage when it was posted. There are a number of players who picked up sizeable parcels in the area and we’ll be talking to them - looking for synergies and opportunities to share and to better understand the basin. To us it looks like it will be a tight gas/tight oil opportunity.

MARK POLAK: And would that be dependent on the Mackenzie pipeline in terms of coming to market?

GLENN SCOTT: It will certainly need an outlet and the Mackenzie Valley pipeline would make it a lot more economically attractive, but we’re a long way away from that. We’ve got to go in and do some drilling, do some tests, find out what the productivity of the reservoir is before we even start preparing a development plan for commercializing a potential resource.

MARK POLAK: Thanks. And then are you able to comment on which play it is in terms of tight oil in Alberta that you’re looking at?

GLENN SCOTT: We actually have quite a bit of acreage that we’ve held for decades that overlies Cardium potential and some other resources. Recently we’ve been working on ExxonMobil Canada properties doing some Cardium drilling and testing. Later this year we expect to move on to Imperial Oil properties in the Cynthia area to do some tight oil drilling in the Cardium.

BRUCE MARCH: Barbara?

BARB BETANSKI: Thank you. Barb Betanski from Addenda. I wonder if you could talk about your target for unit operating costs at Kearl? Unit costs really depend highly on reliability and uptime and when we look at some of the industry challenges in terms of maintenance and operating issues, how should we be thinking about your reliability and uptime targets at Kearl?

BRUCE MARCH: Well, Barbara, our targets are always to be reliable, to run at capacity, and have the lowest operating costs we can. For Kearl, we expect cost to be similar to Cold Lake. That gives you a quantification. And one key thing; when we talk about 345,000 barrels a day at Kearl, that’s bitumen and that’s bitumen production at our regulatory capacity. If you look very carefully at this chart and look at the bar it says Kearl availability, so the steel we’re putting into the ground at Kearl will permit us to produce more than 345,000 on a stream day.

Over time, when we have planned maintenance events or unplanned events, we’ll be able to produce more and catch up. We have a very good expectation and confidence that we’ll be able to average 345,000 on a calendar year because our stream day capacity is larger. That’s what our goal is.

The other key chart for you to think about is this chart (Chart 22). I’ve jumped into in-situ now, but this is a CanOils chart. When we talk about Nabiye, we talk about bitumen that we expect to produce. I think our industry doesn’t do a great job talking the same way all the time, and this chart probably shows that best. Our expectation with Nabiye, just like with

Cold Lake, is what we expect to produce. You can see the history, and the production history from these other nine or ten oil sands in-situ properties in operation varies. The median of production capacity is about 50%. This is what they produce compared to their nameplate statements. I wish there would be a way for you to sort it out better when folks talk about capacity and costs per flowing barrel because I think you’re looking at apples and oranges.

In making competitive comparisons, I really think you’ve got to look at how they perform on an operating basis. Over time, with respect to our operating costs at Kearl or Cold Lake, we try hard to offset the impact of inflation year-in and year-out though efficiencies. We then try to maintain those costs on a same-unit basis as well as we can. If you then go back to Kearl, I think, Barbara, if we keep that calendar year capacity full we’ll have the ability to keep the unit costs as low as we possibly can.

COURTNEY MORRIS: Courtney Morris, Credit Suisse. I have a couple of questions. The first one would be on Kearl. Just wondering what the source of diluent is that you plan to use. The second is on Syncrude. Just wondering if you could talk about the culture at Syncrude and perhaps why it’s taken so long for Exxon procedures to take hold there? Thank you.

BRUCE MARCH: We’re very knowledgeable about diluent because we’ve been using it for our Cold Lake operation for a long period of time. Some of it comes from the refineries in the Edmonton area. They produce light streams which have probably the lowest value for gasoline and can be used as diluent. There’s a pipeline in place that is bringing diluent back from the Chicago area. We don’t have a commercial interest in that today, but if a refinery like Joliet is running a lot of Kearl diluted bitumen, we would be looking to try to return that diluent back and reuse it. Depending on the pace of the growth in the oil sands, particularly the in-situ properties, you could see diluent coming from the Midwest of the United States. It can be imported from the West Coast and could come from places far south via barge on the Mississippi River or up through a pipeline system.

On Syncrude, I really like this chart (Chart 33) - it explains a lot about our challenges.

We’ve brought our tool kit and management systems,and we’ve put a number of people into leadership positions at Syncrude. Overall, this is a pretty good assessment of how well we’re doing and the biggest challenge, without a doubt, has been reliability.

Project management includes turnaround management; planning, scheduling, scope, execution. We’ve made strong progress here with the three fluid cokers all down at least once. We’re on the second round. We’ve been inside and corrected a lot of the initial problems. I think Glenn said it very well that what’s plagued us in the last couple of years isn’t so much the things we fixed, but the robustness of the equipment, and, in particular, how the people, systems, and equipment operating envelopes have been applied.

I think the culture at Syncrude is fine. That’s not our challenge. It’s taken us quite a while to put these management systems in place so that all levels of the Syncrude organization understand how they work, the role that they have to play, and how they bring long-term benefits.

There is an enormous amount of equipment there that all of these management systems - particularly the reliability one - are being applied to. Recently we have experienced failures of certain pieces of equipment that we haven’t had down for a turnaround. They just haven’t been robust enough to last for the planned length of time.

We’re disappointed as well. We continue to work it very hard and our hope going forward is to bring back this very careful matrix. These items here - design, operate, and maintain - are how you build a facility.

You design it right, you get your team to operate it right, and you maintain it right. Our operating experience is that these vertical green bars are more important. Reliability is a complex combination of people, procedures, and the operating systems that the people use. It’s operating within equipment envelopes that you don’t stray away because if you do it will put too much stress on the equipment that and eventually lead to a failure, either in a short time or a longer period of time. It has been most challenging to get these three things right within the Syncrude organization and within their operating culture. We’re confident we’re going to get there eventually.

UNIDENTIFIED SPEAKER: I had a question about - well, before I ask you my question about Kearl, I wanted to talk quickly on the Chemical side. Are you looking to do more like the deal that you did with the Marcellus ethane supply? And can you quantify in some way the competitive advantage that you’re getting from the ethane?

BRUCE MARCH: We have a world scale polyethylene plant that sits behind our gas cracker at Sarnia, and because it’s integrated with the refinery, we also have what we would call advantaged feedstock. The off-gases that come from the cat cracker and the coker that are ethylene-rich are collected and sent through the Chemical operation. Our gas cracker is

smaller than the capacity of our polyethylene plant so we’re constantly looking to buy ethylene or to find optimizations with different feedstocks to produce more ethylene. Because we can’t always get advantaged feedstock, from time to time we crack propane and higher molecules - which is not the preferred way to go.

This Marcellus shale agreement that will come in the middle of 2013 buys enough ethane to basically fill up and have very little heavier than ethane feedstock.

We’re also looking at optimization projects for the gas cracker and the ethylene recovery train associated with the gas cracker. So, modest capital investments designed to see if we can improve ethylene production capacity.

We’re pretty happy with this first step and are studying the second step. We also work with industry in the area, NOVA in particular. Right now they’ve got some equipment problems and we’re buying a lot of their ethylene and running it through our polyethylene facility.

UNIDENTIFIED SPEAKER: Just a follow-on on that, I mean you talked about LNG first, transportation, usage of natural gas further down the road. Where does demand for the chemical industry sit, do you think, in that realm of potential demand increases, given lower gas prices?

BRUCE MARCH: Yeah. It’s my mistake to not include it in...

UNIDENTIFIED SPEAKER: No, I’m sure it’s there, but where does it fall in that time line do you think?

BRUCE MARCH: If you think about the demand for polyethylene, the big new demands are going to be in Asia, India, and that part of the world. Most of their in-place ethylene production starts with cracking liquids. So picture them cracking liquids off a $100 crude price compared to cracking ethane in North America off a $2 gas price. As a result, I think within the industry in North America there’s a large number of new grassroots ethane crackers under study right now, particularly where shale gas is being developed. There’s some that are obvious; the Marcellus, though, is a little far away from a lot of the chemical assets. Shell recently announced a study in the Pittsburgh area and I think you’ll see similar studies in the Barnett and Haynesville areas that are closer to the Gulf Coast. So ethane recovery will be in the early seriatim for uses.

UNIDENTIFIED SPEAKER: Okay. But there’s no date per se in terms of that demand coming on for chemical, like a 15, 16 equivalent for LNG? There’s no sort of year that where it’s visible that chemical demand for ethane is going to kick in as yet?

BRUCE MARCH: I know the industry is rapidly looking at it. It would be hard to do a new grassroots facility by 2015, I think, but it’s getting actively worked because as the shale gas expands and the ethane production expands, you’ve got to be able to do utilize it.

UNIDENTIFIED SPEAKER: My last question was on Kearl. You mentioned at the outset that you had some concerns about regional inflation. So I’m wondering have you seen projects being pushed out? I mean I think the peak was sort of 2015-ish and have you seen projects pushed out as a result of that? And is there an update on the CAPEX budget for Kearl, both Phase I and the expanded portion of it?

BRUCE MARCH: I can’t say I’ve seen projects get pushed out. What we have seen are industry consolidations like Suncor and Total combining, so there’s fewer projects and they’re more moderately spaced. And the Petro-Canada and Suncor merger has had an impact as well. Projects will get executed as labour exists, and the industry’s working very hard with governments federally and provincially to get enough labour to take us through this next rapidly approaching peak.

We don’t have anything specific to update with you today on Kearl initial development CAPEX. We talked about the modules. We talked about the critical path. We’re working very hard to meet the year-end start-up date, but no specific updates.

We’re really just getting started on KEP (Kearl Expansion Project). We’re done a lot of the early front-end work. About 90 percent of the design of the expansion project will just be a duplicate of KID, so you’ll see that go pretty quickly, but nothing specific to update you there either.

You’ve got a question from the webcast?

GEORGE BEZAIRE: We have a question from the webcast, it’s from David McColl of Morningstar and he asked if you could comment on the difference in breakeven production costs for the CSP process versus cyclic steam stimulation, including fuel costs? And also, any comment on SA-SAGD?

BRUCE MARCH: Say that again, George, the breakeven or the...

GEORGE BEZAIRE: There’s a question about the economic comparison between CSP and CSS?

BRUCE MARCH: Well, I think the obvious attraction that we see in a breakthrough with CSP is the fact that you don’t have steam and the energy consumption that goes into developing the resource. However, we don’t know enough about it in a commercial operation today. We have to do the pilot first before we can specifically talk about comparisons versus

CSS, but we think through the lab work and the trial run that we had at Cold Lake that it’s worth pursuing in this three-well pilot. It’ll start-up in 2013; we’ll probably know more by 2015 just exactly what those economics look like.

There’s very little energy in CSP. The only energy we use is the energy to separate the solvent from the bitumen once it’s recovered above ground. The real key to CSP economics, in fact, is how much diluent or how much solvent comes back with the bitumen. We think we’ll be able to recover enough, but the pilot will be the real key.

On SA-SAGD, we’ve been running that pilot longer at Cold Lake. What we can say is that use of the solvent provides up to 25 percent improvement in terms of recovery, but we’ve still got more work to do to fully understand SA-SAGD process.

There’s an obvious trade-off with CO₂ emissions. You could reduce steam and count on the solvent to help you at a fixed CO₂ emission rate, or you can just put in all the steam and then add the solvent and recover more barrels. A lot of that is what we’re working through right now in the SA-SAGD pilot.

GEORGE TORIOLA: Just a quick three-part question. First of all, let’s go back to that chart that you have up on there. As far as Syncrude is

concerned, do you have, based on your operating experience so far, concerns with the design of equipment at Syncrude that suggest a lot of future capital? That’s the first question. Second, I’m looking at your production growth profile going to 2020 as conventional declines. Is that just based on just harvesting those assets? Are there plans to sell some of the assets? And then the third one being the oil sands growth that you have in there, is there a threshold where based on heavy differentials where that growth would not occur? The current differentials we see look like a bump in the road but if this is sustained, at what point do you start to look at that again and decide not to invest?

BRUCE MARCH: On the Syncrude question, I would say, George, we haven’t seen anything that wrong with the design of the equipment at Syncrude. What we have done in the last five years, like any asset, is fix a lot of things to make them better. But there’s nothing from a design standpoint that’s enormously hampering where we are. We have had some things fail unexpectedly and had to go back and modify the equipment envelope or change materials to try to get more run time out of those specific parts. This is something we are battling.

I’m going to jump to your third question here and the answer to that is no. I think what’s going to drive our future growth in oil sands isn’t so

much the discount, but the flat price. With oil prices at $100 a barrel, it pretty much opens up everything. That’s going to drive more future capacity growth than the discount will.

We see the discount and it is near a low today. It’s not driven by anything long term or fundamental. I don’t think we’ve got some short-term things driving it, but it was a year or 18 months ago when we saw the bitumen discount at about 10 percent of WTI. It goes back to the supply/demand balance. What drives our program is more the flat price of oil and demand around the world in general.

Your second question was...

GEORGE TORIOLA: Conventional...

BRUCE MARCH: I’ll let Glenn talk about that.

GLENN SCOTT: The simple answer on conventional is we’re going to harvest what we’ve got. There’s not a big component of future asset sales built into the curves that you saw.

BRUCE MARCH: One up here that hasn’t had a chance yet.

WILFRED PRUHAUS: Wilfred Pruhaus, W. Pruhaus Consulting Ltd. I have three questions. The first one is a follow-up regarding the Dartmouth refinery. In your opinion is there a near-term probability that you might mothball this refinery and use the facility as a storage terminal?

BRUCE MARCH: I won’t comment on that right now. We look, as we always do, at all options, all opportunities.

WILDRED PRUHAUS: The second question relates to bitumen extraction. Quite a few years ago one of your competitors started using counter current decantation and I’m wondering how that compares with the paraffinic froth treatment in terms of efficiency and cost?

BRUCE MARCH: I think you’ve got us on that one. We’re not familiar with counter current decantation technology. I wouldn’t be able to answer because I honestly don’t know much about that technology at all.

WILFRED PRUHAUS: Well, I’ll follow that up later. The third question is what conversion factor do you use to calculate boe?

BRUCE MARCH: For natural gas it’s simply taking millions of cubic feet and dividing it by 6,000 and that gets to an oil equivalent barrel.

WILFRED PRUHAUS: Would I be correct in saying that this overstates really the size of both your production and reserve for gas because the real equivalent is equationally closer to 20 or 22 rather than 6?

BRUCE MARCH: Well, I guess I’m not sure with what you mean, but it’s the standard industry definition that everyone uses and it’s important, I think, as companies talk to investors, to try to be as consistent as we possibly can. If you’re referring to the valuation of gas versus oil, we think there’s enough information out there to just do it.

WILDRED PRUHAUS: No, I’m just referring to the 6:1 ratio. I would suggest wouldn’t it be better to calculate a conversion factor by using netbacks per barrel and netbacks per million BTU and use them to calculate a conversion factor?

BRUCE MARCH: I would say no and here’s why. Again, formally we have to report to the SEC and the TSX through a 10-K and they set up the definitions of how reserves are talked about.

I take your point about the value of the gas on a BTU basis and where pricing comes in, but I think we would suggest that we keep this methodology that’s been in use for a long time and then let individual investors factor in those price outlooks to get to what its true conversion may look like.

PETER OGDEN: Peter Ogden again. Just a follow-up question on refining, and concentrating on three out of the four refineries that are making money, we typically benchmark them off the mid-continent crack spread, which sits at $30 plus. You talked a lot about the WTI Brent differential, but now Canadian crudes and SCO blends are also getting a further differential beyond WTI. You have a lot of Canadian exposure.

Dollar for dollar, do you benefit on the Downstream side from the wider differential in the Canadian and synthetic crudes? And maybe that’s a good time to talk about some of the integration within the Downstream itself. Do you give some of it up on the Chemicals? How does that all kind of come together? Because historically it doesn’t really matter what the crack spread is. You make a very consistent amount of money out of your downstream and I’m wondering if you’re going to benefit from the Canadian crude and SCO differentials?

BRUCE MARCH: Well, I can tell you a little bit—the synthetic crude we run comes from Syncrude and we typically run all of it in our Strathcona refinery. So anything there, a discount or a premium, flows right into Edmonton.

If you look at what we run, 100 percent of our Edmonton feedstocks are WTI-based; as you follow the Enbridge pipeline system, 100 percent of what we run in Sarnia is WTI-based. Today we don’t have the capability to run 100 percent WTI-based at Nanticoke. This is where the pipe needs to be reversed. The NEB is going to have a hearing in the middle of this year to reverse line 9 from Sarnia to Nanticoke. Our desire would be to run 100 percent WTI-based crudes at Nanticoke. Once we get through the hearing, we’ll have about a year for Enbridge to do the reversal work.

So if you add up all the refining capacity that is WTI-based, Peter, I think you’ll find that we run more WTI-based crudes than crude we produce from Western Canada that are subject to those same discounts.

PETER OGDEN: Is it WTI-based or Canadian light sweet?

BRUCE MARCH: It starts with WTI-based and then it goes to WCS for heavies and it goes to Edmonton par for light. So, I think the easiest way for me to answer this would be to focus on the WTI alone, but you can see today our system is bigger on the refining side. I think you see that that we mentioned briefly in our review of the different business segments that refining had a pretty good year and some of it came from the market dynamics.

BARB BETANSKI: Thank you. Barb Betanski again. Just another follow-up question on Kearl and the module construction that you did outside Canada, and I wonder whether you face significant delays due to those issues or additional costs and whether you plan, for the next phase, to change your process or will you be continuing to construct those modules in the same way?

BRUCE MARCH: No question we’ve had delays. The legal challenges in Idaho and Montana have delayed the transport of those modules significantly. And there’s no question we’ve had additional costs, but at this point we don’t have a specific update for you on that.

In making the decision for KEP we’ll go through the same competitive bid procurement process for equipment. We’ll go through the same assessment of module yards, where they are, how much capacity we can get. I think we learned a lot of lessons from what was the right decision in 2008/2009 to go to Korea.

We now know what these legal challenges could be in the future. We haven’t come to a decision point yet but we’re not too far away from it. It really comes down to where you can do all this modular construction. If we can procure it in Edmonton I think that would be our best bet.

JOHN CHARLTON: Bruce, I think you have time just for one more question.

BRUCE MARCH: Okay.

KAM SANDHAR: Hi, Bruce. Kam Sandhar with Peters. I just have three questions. First of all, just wondering if you could comment on what your expectation for Kearl’s maintenance capital costs are because we are seeing a big variation on that across the industry.

Second question, you guys talk about other mining leases outside of Kearl. I’m just wondering what stage of development you’re at and whether you have any sort of specific time lines on when you would pursue those?

And then the third question just on Aspen. Just wondering if you could comment a bit on what sort of reservoir characteristics there are there, what sort of SORs you would anticipate for a lease like that?

BRUCE MARCH: Okay. I’ll let Glenn take all three of these. First one, Kam, you asked about sustaining capital at Kearl.

GLENN SCOTT: The sustaining capital, I don’t have a number to give you if that’s what you’re looking for. I would say I’ve read some of the estimates that are out there and based on our current view, it’s probably lower than the estimates that I’ve seen.

We’ve tried to build in upfront, in our design and construction, to have high reliability that will last for the full life of the asset so that the draw on future sustaining capital will be relatively low. We will have to add trucks as we expand the mine face and as the mine face gets further away. We’ll have to add shovels similarly, but the cost that we’ve talked about to date - the $6.20 per barrel - that will get us to the full 345,000 per day and deal with the tailings to comply with Directive 74.

We’re trying to design our tailings program so that we only have to handle the material once. We’re not depositing it in a tailings pond, then having to treat those tailings sometime later in the future through some chemical process, then having to move those back to another location and then having to reclaim. We’re designing our tailings treatment program to allow us to treat and put back into the pit right away and handle that material once. So a lot of the sustaining capital costs that you see at, say a Syncrude, we hope to avoid.

Second question again, Kam?

BRUCE MARCH: Other mining after Kearl?

GLENN SCOTT: Yes. Those are a little further out there. We’ve told you about everything that we see coming on within the next decade. The next ones out of the chute look to be the Aspen and the Grand Rapids at Cold Lake. Those are upfront in our focus to get us to the 600,000-ish barrels a day kind of number by about 2020. We do have lots of other mining leases that we’re currently looking at. We’re trying to balance the pace of those in our planning process with some of the new technologies that we’re developing to try to make sure that we don’t get too far out in front with one versus the other. Ideally, I’d like to bring to bear some of these game-changing technologies on the next mine that we develop. And so we want to make sure that we pace those accordingly.

Steam-oil ratio on Aspen I would say is going to be comparable to industry. I wouldn’t say we have anything special in terms of our current development plan thinking.

BRUCE MARCH: Okay. Well, thank you very much for your participation and your interest in our company today.

We appreciate having all of you here, and I think we’ll have a light lunch available for those of you that are interested and we could continue to talk and discuss our business in a little bit more detail.

Thanks for coming today.

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