Natural Resources Committee on Jan. 31st, 2012

[The Chair, Conservative, Leon Benoit]

Good morning, everyone.

First, welcome back. This is our first committee meeting since Christmas. I hope you all had a bit of a break and then some good time with your constituents.

We are here today to start a four-day session, pursuant to Standing Order 108(2), to do a study on the current and future state of oil and gas pipelines and refining capacity in Canada. This is a topic that we all know Canadians will be paying attention to, and I'm looking forward to the presentations and to your questions and comments throughout the four days.

Today we have three groups of witnesses. First, from the Department of Natural Resources, are Mark Corey, assistant deputy minister, energy sector; Douglas Heath, director, oil sands and energy security division, energy sector; and Michael Rau, senior policy advisor to the assistant deputy minister, energy sector. Welcome.

From the Canadian Petroleum Products Institute, we have Peter Boag, president; and Carol Montreuil, vice-president. Welcome to you.

As an individual, we have Hossam Gabbar, an associate professor at the University of Ontario Institute of Technology. Welcome to you.

We will have presentations of up to 10 minutes for each group, starting with the department. Mark Corey, go ahead, please, sir.

[Mark Corey, Assistant Deputy Minister, Energy Sector, Department of Natural Resources]

Thank you, Mr. Chair.

I think that we have distributed our presentation document. The purpose of my presentation is to give you an overview of the petroleum refining industry. I will begin by describing the refining process as such. Then, I will provide the committee with an overview of the Canadian petroleum refining industry. Finally, I will talk about the factors affecting investment in the refinery sector.

Again, I'm just going to go through the deck here.

On the slide where we talk about what refining actually is, this is very much an oversimplification, but refining is basically just boiling crude oil. If you look at the slide, you can see that what it's actually doing is adjusting and reshaping the hydrocarbon molecules, standardizing the product, and removing contaminants. That's an oversimplification, but that in a nutshell is what refining does. Crude oil is boiled, the vapour is condensed in a tall distillation column, and different components are drawn off as they condense separately at each level in the column at different temperatures. You can see, for example, that gasoline comes out at the top, and lubricating oil, paraffin wax, and asphalt, the heavier ones, come out at the bottom. You have other products in between.

Now, that's a real oversimplification, but that's essentially what refining is. Again, I'd let Peter Boag from CPPI probably go into more of the technicalities of it, as that's the industry side of things.

The next slide is just to show that the amount of different products that can come out of a barrel of crude oil can vary. That's one of the things that refineries do through various processes. They can get more or less gasoline and more or less diesel, for example, out of a barrel of crude depending on how it's refined.

Conversion is required. The processes use high temperatures and chemical reactions to separate products by changing their chemical structure. This involves removing impurities such as sulphur and nitrogen to meet regulatory and seasonal requirements.

Refineries get more complex and expensive to build and operate based on the heaviness of crude they handle. Again, refineries that are processing crude oil are bigger and more expensive than ones that produce light crude.

Each refinery is often of a different design, based on the existing technologies and anticipated market needs at the time of construction. They adapt to the marketplace. For example, North American refineries tend to be set up to produce more gasoline and less diesel because we have more need for gasoline. European refineries do it the other way. They actually are set up to produce more diesel and less gasoline.

So that's what refineries do. They can actually vary the amount of different products that come out, depending on how they're processed.

The next slide is just to show that even though North America is an integrated market, Canada really gets its crude from two different sources. Western Canadian refineries use domestic crude, and western Canada supplies the majority of crude used by Canadian refineries that's transported all the way from southern Ontario, Sarnia, to Vancouver. Specifically, refineries in Ontario use largely now domestic crude—approximately 85% Canadian crude in 2011—but still bring in some imported crude from the east coast. The imported crude, the other 15% coming in, is from North Dakota, 4%; and Norway, Angola, and Equatorial Guinea make up about 11%.

In terms of refined products, product is moved from the refineries to supply terminals through a variety of modes, including pipelines, trains, tanker trucks, and tanker ships in the east. Western refineries supply all product demand from Vancouver to Thunder Bay and the territories. In addition to supplying local markets, refineries in southern Ontario also move product to Sault Ste. Marie in northern Ontario.

If you go to the next slide, you can see that in eastern Canada it's different. In eastern Canada, crude oil comes either from the Canadian offshore off Newfoundland, which is 15%, or imported, which is 85% via tanker into Halifax, Saint John, or Come By Chance from countries such as Algeria, Nigeria, the United Kingdom—that's from the North Sea—and Norway.

In Quebec, crude is imported via smaller tankers into Lévis or by larger tankers into Portland, Maine, and then via the Montreal-Portland pipeline into Montreal. Again, for Montreal there is a pipeline. I think the capacity is that about 600,000 barrels a day come in from Maine and go to Montreal.

An indication of the refinery sector's competitiveness is the fact that today Canada is a net exporter of refined products. In 2010 we imported 223,000 barrels per day of refined product, mostly into Quebec and Atlantic Canada, while at the same time we exported 419,000 barrels per day of refined product, largely into the New England states. Again, this is the phenomenon where some of the refineries in eastern Canada will import crude, process it, and ship it on into markets in New England.

Petroleum products come from two of three Atlantic refineries that supply local markets but also find their way to the Arctic and Hudson Bay regions as well as the eastern seaboard, which is what I just mentioned.

Montreal and Quebec City facilities supply some of the more remote areas of northern Quebec and occasionally parts of the Arctic as well as the St. Lawrence River corridor from eastern Ontario to the Gaspé Peninsula via the Trans-Northern pipeline. In northern Canada, weather-dependent delivery systems, mainly by ship, mean that some delivery windows are very narrow. Again, a seasonal “sealift”, as they call it, goes up to northern Canada with refined products.

The next slide deals with the state of the industry today.

Currently there are nine companies operating 15 full petroleum refineries in Canada. They produce a full range of products, such as gasoline, diesel, and jet fuel. There are four partial refineries, which produce asphalt or petrochemicals: two are asphalt facilities in Moose Jaw and Lloydminster, and two are petrochemical facilities in Mississauga and Sarnia. Nationally, Imperial Oil, Shell, and Suncor operate more than one refinery.

One thing to point out is that the refining sector has undergone significant rationalization since the 1970s. The rationalizations in the 1970s and 1980s were a result of a decline in demand caused by price shocks at the time, which led to vehicles becoming more fuel efficient. Demand subsequently recovered, and this recovery encouraged not the building of new Canadian refineries, but the expansion of existing refineries to add capacity.

National capacity today is higher with 15 refineries than it was with 44 refineries in the 1960s. In other words, while we talk about the fact that we're closing refineries and have fewer of them, the capacity of individual refineries is expanding and we actually have more capacity today than we did in the 1960s. Over the last 10 years, for example, we've seen two refineries close, but total capacity has held steady.

The next slide deals with something that Peter Boag will probably go into more deeply.

Refinery utilization rates were above 90% early on in the previous decade. However, since the 2008 recession, they have dropped to 80% in Ontario and western Canada, and to 84% in Atlantic Canada and Quebec. In 2011, the refinery utilization rates in western Canada were slightly affected by hydrogen availability issues, a refinery fire and other minor maintenance issues.

The industry aims for a 94% or 95% utilization rate, which would maximize operational efficiency while allowing for normal maintenance and seasonal turnarounds. Therefore, refineries are currently operating below optimal levels.

The next two slides deal with where refineries and operators are located, something we touched upon earlier.

There are five factors that drive where refineries and operators are located. We work in a market-based system in Canada, so it's really the market that determines where these things are going to be located.

The first factor is capital cost for new upgraders and refineries. North America is really a single integrated market, and companies don't make investments in isolation. The United States' gulf coast has 58 operational refineries that represent 50% of the refining capacity in the U.S., with considerable idle capacity to refine heavy crude oil. Refineries are very expensive. They can cost anywhere between $5 billion and $15 billion to build, so if you have a refinery that is already built, with idle capacity, it is really much more economic to try to get the capacity up in that refinery than to try to build a new one.

The U.S. gulf coast requires little capital investment to be able to process diluted bitumen coming out of the Canadian oil sands. In the situation they are now in, stocks coming principally out of Mexico and Venezuela are declining and need to be replaced, so this increases the demand for heavy crude such as that coming from the oil sands, reduces price differentials, and reduces the need for major new capital investments at present. That is one of the reasons the proposal for the Keystone XL pipeline was there: it was because this infrastructure of refineries on the U.S. gulf coast, which was already set up to do heavy crudes, was losing feedstock from Mexico and Venezuela. That's what is driving the economics behind that.

The second factor is price differentials. If the cost of crude plus the cost of refining is not significantly lower than the cost of refined petroleum products, then there is not that much incentive. The same holds true for upgrading. If the cost of raw bitumen plus the price of upgrading is not actually more than the price of conventional crude, then again there is less of an incentive. An economically rational company basically seeks to maximize its returns, and this all works its way out through the marketplace.

The average price differential has varied considerably between the price of crude—refined and upgrading—and the actual cost of refined products over the years. That's what drives the decisions to either invest in refining or not.

We'll see in the next slide where the capacity utilization is as a result of all these factors right now.

The third factor is contamination. Refineries tend to serve regional markets, although there is some long-distance shipping by ship. Transporting crude does not have the same contamination challenges as transporting refined products. Shipping refined petroleum products over long distances and over multi-product pipelines can lead, for example, to increased sulphur levels, requiring costly remediation at the final destination, so if they're shipping long distances by pipeline, shippers tend to prefer to ship crude and then refine it closer to market. For example, airports often have dedicated lines from a local refinery to the airport for jet fuel. In Canada, for example, airports in Vancouver, Edmonton, Calgary, Toronto, and Montreal all have dedicated pipelines.

The fourth factor is distribution infrastructure. Shipping one product through a pipeline is easier and cheaper than shipping several products in batches or having separate dedicated pipelines. When you're shipping crude, you're shipping one product; when you're shipping refined, you're shipping multiple products. The input to refineries is crude oil, whereas products are likely to be gasoline, diesel, and jet fuel. It's more complicated and costly to transport multiple refined products long distances to customers at many end destinations.

The fifth factor is fuel specifications and seasonality. This is interesting, and it's something that most motorists don't know: fuel specifications are extremely stringent and are tailored to the climate within which the fuels are consumed. Gasoline consumed in a warm climate is blended differently from that consumed in a cold climate, and in the same area, specifications will change seasonally. Transporting crude oil versus refined products also provides fuel suppliers with the flexibility to produce different products in response to seasonal demand, for example, heating oil versus gasoline.

We will move on to the summary to put that all together.

Generally speaking, western Canada and southern Ontario refiners mostly rely on western Canadian crude oil, while eastern Canadian refiners largely use eastern Canadian offshore crude oil and imported crude oil.

Our refineries today are fewer in number, but they are much larger and more efficient than they were 50 years ago. Canada refines more petroleum products than it consumes and is therefore a net exporter of both petroleum products and crude oil.

Canada's crude oil reserves are the third largest in the world. As production increases, it is likely that the amount of Canadian crude oil refined in North America will continue to increase.

[The Chair, Conservative, Leon Benoit]

Thank you very much, Mr. Corey.

We go now to the Canadian Petroleum Products Institute.

Go ahead with your presentation, please, Mr. Boag.

[Peter Boag, President, Canadian Petroleum Products Institute]

Thank you.

Good morning, Mr. Chair and members of the committee. I'm very pleased to be here today to provide perspectives on the committee's study of pipelines and refining. I'm happy to have Carol Montreuil, vice-president of our eastern Canada division, here with me this morning.

CPPI members play a key role in Canada’s energy value chain. They make a significant contribution to many sectors of Canada’s economy. I think you would all agree that transportation fuels are a vital enabler of Canada’s social and economic activities in that they provide that essential fuel that moves people and goods across our country.

Our submission, along with some other pertinent material, is contained in the packages that have been distributed to you. In my remarks this morning I'll highlight the key points in our submission and focus on four themes. The first is a snapshot of Canada's refining sector, which supplements the information Mr. Corey has provided.

The second is to clarify the distinctions between bitumen operators and product refineries—I think there is some general confusion around that issue. The third is to compare and contrast the market challenges and opportunities for Canada's petroleum product refiners and our oil sands producers. The last is to reinforce the role we think public policy-makers can play in promoting a competitive and viable Canadian refining sector.

First is that snapshot. CPPI members have been providing quality and reliable petroleum products to Canadians for more than one hundred years. The industry today contributes $2.5 billion annually to Canada’s GDP. It employs 17,500 highly educated and well-paid refinery workers. In Canada overall today there are 19 refineries located in eight of our provinces, and they have an aggregate production capacity of about two million barrels per day. CPPI members operate 16 of these 19 refineries. In addition to refinery infrastructure, there are 70 distribution terminals and some 12,000 retail sites across Canada that employ 82,000 workers in total.

Refiners produce gasoline, diesel, and aviation fuels, as well as heating oil, and important feedstocks for the petrochemical industry. Some CPPI members are also significantly involved in the production of biofuels, and certainly virtually all Canadian refineries and petroleum producers are now involved in the distribution of biofuels.

As Mr. Corey pointed out, Canada is self-sufficient in and a net exporter of refined petroleum products. Our sector exports about 20% of its output—about 400,000 barrels a day—mainly to the United States and mostly from Quebec and Atlantic Canada. Geographic proximity to the very large northeast U.S. market and the ability to ship by sea or ship relatively short distances to market are key factors that facilitate these exports.

Now, refining is, again, as Mr. Corey pointed out, a very capital-intensive business. It's one of the most capital-intensive businesses in our economy. A typical new refinery would cost in excess of $7 billion to build today, and that doesn't include the land acquisition costs that would be associated with that. While no new refinery has been built in Canada for some 25 years, more than $40 billion has been invested in Canadian refineries since 1980. That's including the capacity expansion of the kind Mr. Corey has already spoken about. As well, it's directed at continuous improvement initiatives to increase operational efficiency, to enable the refining of heavier crudes, and of course to improve environmental performance.

On that point alone, over the past 10 years, a total of $8 billion has been invested in environmental improvements to Canadian refineries. Currently, CPPI refiners invest close to $3 billion a year in aggregate to sustain their competitiveness in an increasingly challenging global market for refined petroleum products.

Canadian refineries are efficient, but they are not large by international standards. They operate at a size and complexity disadvantage to U.S. refineries and at an even greater disadvantage to some of the new super refineries that are being built in Asia. A good illustration is that we now have one refinery in India, on one location, on one site, that has the capacity to produce 60% of all Canadian refinery output—1.2 million barrels a day from one site, compared to Canada's two million barrels from 19 sites.

Refining economics generally dictate that refineries be located close to consumer markets. Again, as you've heard from Mr. Corey, transporting finished products such as gasoline, diesel, and aviation fuel, especially over great land distances, is more expensive and logistically less efficient than transporting crude oil.

This is a common theme for many commodities that are traded globally. As Canadians, we export a lot of wheat, but we don't export baked goods. Certainly as coffee drinkers we import a lot of coffee beans, but we don't import brewed coffee. So this is consistent with a lot of commodities.

However, the economies of scale of some of those larger refineries that I've talked about, and also the access to ocean shipping, substantially mitigate the economic impediments of transporting finished products to distant markets. So this does pose significant new competitive challenges for Canadian refineries, increasing the importance of refinery efficiency and the requirement to be globally competitive.

A big part of refinery efficiency is operating at or near capacity; optimal capacity utilization is over 90% and preferably close to 95%. Currently there is excess refinery capacity and below optimal utilization across North America. The latest National Energy Board figures show that through 2010 and 2011 the utilization rates in Canada were in the low 80% range.

As we've seen those low utilization rates across North America for the last several years, there has been some continuing consolidation and a number of refinery closures. One has closed in Canada in the last couple of years. Three refineries have recently been closed or idled on the U.S. eastern seaboard. Two weeks ago, a large refinery in the United States Virgin Islands announced that it would cease operations next month. That's indicative of the kind of business environment we operate in right now.

On product refineries versus bitumen upgraders, there is some confusion over the nature and roles of refineries and upgraders. Often the terms are used interchangeably, but let me emphasize that petroleum product refineries and bitumen upgraders are not necessarily the same. Product refineries are built and configured to process crude oil from heavy to light, from sour to sweet—and now synthetic—into products such as gasoline, diesel, aviation fuel, and home heating oil. They're generally much more complex than a bitumen upgrader due to the nature of the multiple products they're designed to produce.

Mr. Corey has already provided a very high-level summary of the refinery process, so I won't repeat that, but I will emphasize that no two refineries are identically designed and engineered. They do share a number of common features and processes—distillation and cracking—and they use similar state-of-the-art technologies, but specific refinery configuration and process units are employed.

The specific refinery configuration and process units employed are generally determined by the crude oil diet that is available to the refinery and the kinds of products they want to produce that are driven by local market demand conditions, and this is obviously something that is not static. Other factors that do affect refinery configuration are the technological requirements, or the technology available at the time of construction, and of course the way the refinery has evolved over a long period of years to adapt to a changing marketplace situation and/or changing environmental regulations in the relevant jurisdiction.

So no two refineries are alike. In fact, they can be quite substantially different.

Bitumen upgraders are specifically built and configured to produce a 100% bitumen feed, or “dilbit”—diluted bitumen. It's a form of crude oil, but it has physical and chemical properties that are generally unsuitable for use as a refinery feedstock. So upgrading is an intermediate process whereby bitumen is transformed into higher-value synthetic crude oils suitable as a feedstock for some but again not all refineries. So while a bitumen upgrader may employ some of the same processes used in a products refinery, it's configured differently to address the specific challenges of the high viscosity and extra-heavy physical and chemical properties of bitumen.

Complicating this distinction, though, is the fact that the operational and process boundaries of a refinery and an upgrader are not clear cut. There's not a clear line to say this is a bitumen upgrader and that is a refinery. Some product refineries can process bitumen and heavy crudes; generally that means they employ a coker. Some upgraders produce limited amounts of finished products, generally diesel. Also, an upgrader and a refinery can be integrated into a single facility. It's not a clear-cut distinction, but in general, upgraders and refineries are different.

Moving on to the differences in market challenges between the refining sector and the oil sands industry, certainly Canada’s refiners and oil sands producers live in very different worlds and face very different market challenges and opportunities. There is no question that the upstream and oil sands industry provides a tremendous catalyst for growth in Canada. Growing demand for crude oil, especially from developing economies, is projected to increase for the next 25 years and beyond. This creates attractive export opportunities for Canada’s upstream sector. On the other hand, North American demand for refined petroleum products over the same period is expected to be essentially flat. This fact and the challenges it creates for Canadian refiners were highlighted in a recent Conference Board of Canada report. That report is included in your package.

The fact that petroleum fuel demand has likely peaked, or has nearly peaked, in North America may come as a surprise to some, but it's a phenomenon that's experienced in virtually all OECD countries, where demographics, mature transportation systems, new vehicle fuel efficiency regulations, and a growing market penetration of alternative fuels—biofuels and natural gas, for example—and electric vehicles combine to offset any growth in overall transportation energy demand as we move forward for the next 25 to 30 years.

In this context, to go back to some earlier discussion, North American product refining capacity now essentially exceeds demand. Furthermore, the North American refined product market is increasingly exposed to imports from new global supply capacity, especially in the developing economies of India and China, where these massive new super-refineries are operating or being built.

Building new refinery capacity in Canada in this context is a tough sell. It’s hard to justify spending $7 billion on a new refinery when there is already more than enough supply on the continent. However, it is understandable that with increasing production from Alberta’s oil sands, there is an expectation, at least in some circles, that Canada’s refining capacity should also grow. However, the economic truths of supply and demand in the North American context often get lost or ignored in the debate, and the realities of declining North American demand, excess refining capacity, and stiff competition from overseas refiners often get overlooked.

These economics get even tougher when the geographic realities are considered. Alberta, home to most of the oil sands, is landlocked, and far from major refined-product markets in the U.S. Similar economic realities apply to the argument that we should be upgrading more, if not all, of our bitumen in Canada. Certainly we are increasing our amount of bitumen upgrading capacity. There are new upgraders online. Canadian refineries have been, over time, changing their configuration to be able to upgrade more synthetic crude, or more diluted bitumen, but there is a limit. The excess U.S. gulf coast capacity that Mr. Corey spoke about is a major investment hurdle for building new capacity in Canada.

Finally, then, there's the role of policy in helping to sustain a viable and competitive Canadian refining sector. Certainly sound economic policies and smart, predictable regulations are key enabling factors for a competitive and viable refining sector in Canada. Success, in our view, demands a sound science-based approach to developing new regulatory requirements that include credible and rigorous economic impact and cost-effectiveness analysis. Regulatory structures that are outcome-driven and provide refiners with flexibility to develop and implement the most cost-effective options to meet regulatory requirements....

I go back to that characterization of our refineries that no two refineries are alike. A one-size-fits-all approach that prescribes how refiners need to do their business really doesn't work for us. We need an outcomes-based regulatory approach that allows those refiners to determine what is the most cost-effective approach to respond to and achieve regulatory compliance given the nature and configuration of their refinery. This is essential if we're going to continue to overcome the scale and competitive disadvantages that we face, particularly from refiners abroad.

Policy-makers can play a significant role in promoting a globally competitive and viable Canadian refining sector: they can contribute to or detract from Canadian refinery competitiveness through the policy choices they make.

In conclusion, the future size and scope of Canada's refining sector will really come down to how well we can stack up competitively in what is a highly competitive and increasingly global market. Can Canadian refiners successfully compete to maintain or grow market share in what is in North America a stable or possibly shrinking fuels market? Can Canadian refiners displace current U.S. domestic supply and imports abroad with more Canadian exports? These are important questions.

In the end, the size of Canada's petroleum products refining sector will be market-driven and will be the sum of many individual business decisions influenced by a myriad of factors, including commercial strategies, crude availability and cost, logistics and labour issues, product demand and market access issues, and of course the Canadian policy and regulatory environment.

Thank you very much. I look forward to your questions.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Boag, for your presentation.

The final presenter today, appearing here as an individual, is Hossam A. Gabbar, an associate professor from the University of Ontario Institute of Technology.

Welcome, sir. Go ahead with your presentation.

[Hossam Gabbar, Associate Professor, University of Ontario Institute of Technology, As an Individual]

Thank you very much. It's my pleasure to be here. I'm delighted to be with you here to share some of the thoughts from the R and D and the research perspectives.

First of all, I belong to the Faculty of Energy Systems and Nuclear Science, in which we study energy from the perspective of economic and social impacts as benefits to society. So we study oil and gas as part of the energy supply chain. Accordingly, when we deal with oil and gas, really as one resource—a natural resource, an important resource in Canada—we always compare and try to find its position versus other resources.

My first image is where we started talking about the map—we call it an energy map—to find out if we would like to capitalize and to strengthen our oil and gas industries and what the motivations for and limitations of doing that might be.

First we said, okay, let's try to map what we have as energy, including oil and gas. We started building the generation side. From the generation side, we built energy bio-power, nuclear power, thermal, hydrogen generation, solar, wind, geothermal, and other.

I just took you one step further up, where we found that we can build a reliable infrastructure for a gas network, for a thermal network, and for an electricity network. The idea here is to say that if we would like to say we have water finally in a certain region, how can we improve it? Do we need to upgrade it, maintain it, extend the lifetime? In order to answer these questions, it is primarily two factors, and these factors are related to the fact that it is supporting a regional area as transportation lines.

So I think the first image I would like to emphasize is that if we would like to really evaluate and make a proper plan for the oil and gas industry for the coming period, one thing we need to do is to see the needs and do a comparison with other energy sources in the region and internationally.

The second thing to look at is refined versus crude oil, which is a very important question, and one that I think everybody is trying to resolve. I would say at this point the question, when we have natural gas and crude oil, is whether we should proceed and extend the refinery. Doing so is very important for the Canadian market as well as the international market if we want to actually export the crude oil.

In order to answer this, again from a research perspective, we started our analysis by saying that we would build a model in which we would define the inputs and outputs for each entity such as a refinery or pipeline, upstream or downstream. And we tried to build in the parameters, which are the performance indicators, and see these parameters—economic parameters, environmental parameters, even HQP. In our terminology, HQP is high-quality personnel, including new-generation engineers and persons working in industry. Based on this model, we try to optimize and maximize the benefit from oil and gas.

This is a generic overview just positioning oil and gas. If we would really like to promote the oil and gas industry further, there will be a parameterized mathematical formulation that will determine that this approach is definitely the way to go based on optimization.

Looking at the oil and gas industry in more detail, in terms of generation, of course, gas represents 16% of the energy distribution. Nuclear is 33% and hydro is 23%. That means gas is actually a major contributor to energy in Canada. In terms of how to map this, we found, from the statistics I provided to you, for example, that Newfoundland generates around 18,000 cubic metres, and Nova Scotia and New Brunswick are around 48,000.

I have provided some information about the statistics we collected so far from the oil and gas industry, in terms of actual generation or production. We have tried to map these values to the actual geographical map and to say, for each region, what the local requirements are and what the sustainable factors are for each region.

Based on that, what we try to actually emphasize is whether we can sustain locally to minimize the transportation: can we balance the need for transportation versus local sustainability? That was one of the factors we tried to analyze. We found that it is primarily related to each region's requirements and needs as generation is available in that region. So from the map, from the projected figures we got from the actual oil and gas production, such as what I've provided, we found that it is very important to optimize the energy locally in each region based on the input-output parameters for each particular region.

I would like to go further into this, and in particular into the picture of where the crude oil chain goes. We have the wells. Crude oil and natural gas go to gathering pipelines that go to oil and gas processing facilities. This is a very simplified picture. That goes to feeder pipelines and then to transmission lines, which are bigger. That goes to a smaller size, which is the distribution—the LDCs—and then to homes and industry. That means we have a network. This infrastructure is not only a refinery but actually a network: from the generation, from the wells up to the processing upgraders, and then up to the end user. This means that if we would like to focus only on the refinery, that's only one element in the supply chain.

So in regard to that refinery's characteristics, from the top view, if we would like to optimize it in such a way as to maintain its maximum function or its maximum key performance indicators, we have to look at this upstream and downstream. Transmission lines are quite large, over long distances. If we'd like to see where to go in terms of maintaining existing refineries, increasing or expanding, developing a new refinery, or transporting the crude oil into the U.S. or internationally—primarily the U.S.—that means we need to model this network. Modelling the network actually includes the characteristics of the material, of the oil, the cost of maintaining the infrastructure, and then costs or the benefits or the value of the oil and gas products.

With this picture, I always feel that it is very important that we build the model dynamic with existing current production. Putting in our requirements and strategy will enable us to actually refine the policy around this supply chain.

If you would like to go to the end of the supply chain, which is actually the products, what we have as products, I have a picture of where we have the whole fractionation, or the situation or the refinery process, if we can say that—a simplified one. We have the crude oil and the generic products. So in the end, each product actually has its own supply chain. We have the fuel that goes to vehicles or transportation. We also have some products that go to jet fuel and also to diesel fuel for trains, and some for lubrication, fuel oil, grease, and asphalt, etc. We have quite a spectrum of products.

The question is.... A refinery is quite a dynamic process, where we can actually tune it in a way that can generate what we like to generate. This means that in a dynamic manner, with adaptive systems or adaptive refineries—I would say smart refineries—we can actually focus more on a product that we are interested in producing.

Let's take a vehicle as an example. As we know, there is the PHEV or plug-in hybrid electric vehicle, so if there is a rule or a policy or a direction to go into electric vehicles, it means that while we are talking about the refinery production or tuning or maintaining its operations, we need to have a look at what's exactly running into that electric vehicle, because it's a factor.

In Ontario, I am actually a member of something called the PHEV—plug-in hybrid electric vehicle—initiative, where we are thinking about how if we want to do electrification for a vehicle, what is the best way to do it? That definitely would affect the supply chain of oil, gas, and fuel. Accordingly, what I want to say here is this: each of these elements actually has a supply chain.

If I would like to maintain the refinery as one element, I need to be 100% sure that the supply chain is maintained properly, upstream and downstream. In addition to analysis on a case-by-case basis, what I strongly recommend in terms of actually evaluating that supply chain is having a real-time simulation for that supply chain that can show us parameters and what-if scenarios: if we contribute 80% of the electric vehicle, what will happen upstream? What if we implement 90% of the electric vehicle? What will we get? That was one of the pictures I tried to emphasize here.

Finally, in terms of the refinery itself, the last thing, as I mentioned, is the dynamic and adaptive aspect. The refinery involves a lot of processes. One of them is physical, thermal, and catalytic, which is chemical. That means we can actually adapt and attune and improve the refinery process.

My last comment in terms of improvement is about integrity. A lot of integrity requirements need to be maintained in terms of physical and mechanical integrity. Second, modifications can be made in terms of energy savings. We can actually improve the refinery's energy saving by maybe 20%. That is a good factor and a big factor. In terms of research, we have achieved something similar to 20% improvement in energy, and environmental and safety aspects as well.

That's primarily a quick review of my discussion.

Thanks a lot, and I'll be pleased to answer any questions.

[The Chair, Conservative, Leon Benoit]

Thank you very much for your presentation, Mr. Gabbar.

We'll now go to questions and comments. Just before we do, I want to welcome a couple of new members who will be on our committee, Joe Daniel and Royal Galipeau. Welcome to our committee.

We go now directly to questions. Mr. Calkins, you have up to seven minutes.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

Thank you, Mr. Chair. Hopefully my voice will get through the seven minutes.

Thank you, Mr. Corey, for coming back to committee. You'll remember a question I asked you a little bit earlier; I want to ask you the same question again today, insofar as we have a few more people paying attention.

Other points of view or voices in Canada are saying that we should be refining and upgrading more products here domestically, rather than shipping bitumen or raw products out of Canada. This is something that strikes home very much to me as an Alberta member of Parliament.

I notice in your deck that in Canada, particularly in eastern Canada, we import crude oil, but nowhere in your presentation did you say that we actually import any refined products into our country. Is it fair and reasonable to assume that Canada should be able to solely export refined product while it's perfectly okay for us to import crude oil from other countries? There seems to be a bit of a double standard there.

Mr. Corey, could you elaborate on why the market is choosing not to upgrade or refine more product in Canada, particularly closer to the point of extraction in Alberta?

[Mark Corey]

Thank you.

Mr. Chair, there are a number of reasons that drive it. To underline the policy of the Government of Canada, we take a market-based approach; we have had that approach consistently I think since the 1980s. There are a number of factors that drive whether or not it's upgraded in Canada.

One thing to put into perspective is that Canada consumes about 1.8 million barrels of oil per day. If you multiply that out, that puts annual consumption around 650 million barrels a year—it's in that range. We have crude reserves of about 174 billion barrels, of which 170 billion are oil sands. That could grow to about 300 billion barrels, as the technology progresses and it becomes more economically viable. It's a massive reserve. Most people don't understand just how huge the oil sands actually are. It will be exported; it's way bigger than anything Canadians could ever use for the next couple of hundred years.

As to where that is actually upgraded and refined, it depends on a number of factors. As we said, one factor is capital cost. As Peter mentioned, the cost of a new refinery is probably in the range of $7 billion to $10 billion; one doing heavy crude is going to be more expensive, and this is heavy crude.

The other analogy I heard was that saying we shouldn't be shipping diluted bitumen is like saying we shouldn't be shipping wheat, we should be shipping baked products only. I think that was one of the analogies that was used. But actually, diluted bitumen does have a high value as an export.

Another factor is contamination. If you're doing pipelines and stuff like that, it's actually cheaper and easier sometimes to ship crude than it is to ship multiple products, as we mentioned.

Seasonality and fuel specifications are other reasons for why gasoline, in particular, is often refined closer to markets.

Those are some of the things that actually drive it. The Province of Alberta—again, I have to underline that the provinces are responsible for the resource—does have a goal of two-thirds of the oil sands being upgraded by 2020. As a province, they've been really promoting it, but in the end it's the market that actually dictates it. I think you can look at it and say the fact that we do have surplus refining capacity right now, with our refineries operating at about 80%-83% of their capacities when the ideal is closer to 93% on the refining side, makes it difficult to make the case that we should be building more refineries in Canada.

Upgrading kind of fits into that picture as well. There are a number of refineries that are set up to do heavy crude. As Peter was pointing out, often that includes the upgrading side of it in the gulf coast. The market basically decides that a lot of that should be shipped to be refined there, and that's probably why the market is doing that.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

I'm going to move on to Mr. Boag.

Thank you for coming, and thank you for your presentation today. Thank you for clarifying the difference between an upgrader and a true refinery. That gives us the full suite of products. There is a lot of confusion about that.

Mr. Corey just spoke about the fact that upgraded bitumen, or synthetic crude, is actually a high-value product. In my particular riding, we have midstream processors for natural gas that create the diluent, which is piped up to Fort McMurray, where it is then mixed with the bitumen so that it can be piped down to the upgraders in Fort Saskatchewan. That creates jobs all over in my neck of the woods, and we're a thousand miles away from the oil sands.

Because Mr. Corey also talked about the fact that we're not running at full capacity, Mr. Boag, I'd like to ask you what the price impact at the pump would be if we were running at full capacity.

[Peter Boag]

I think the price impact is determined by a whole pile of different factors. I certainly would remind you that, number one, about 80% of the price at the pump is reflected in the price of crude and taxes, so what we're now talking about is a relatively small amount. As you look at past price trends over the last 15 to 20 years, at higher levels of utilization margins do go up, and at lower levels of utilization the refinery margins do go down. But the actual gap in the difference is fairly insignificant.

[Blaine Calkins, Conservative, Wetaskiwin, AB]

Mr. Chair, I have one more question. This might be better directed to the Canadian Energy Pipeline Association. I sure hope they're going to have an opportunity to participate.

A couple of you have spoken quite eloquently about what would happen if we tried to do more upgrading and more refining in Canada and the impact it would have on shipping, with contamination and so on. Basically we have a lot of single-purpose lines going out of our country into the export marketplace. If you try to use those lines for different purposes or for shipping different products....

Are pipelines generally built to handle a specific kind of product? Are they designed to handle the full suite of products? What are the costs? What would we see for an increase in costs, Mr. Boag, if for example we tried to run bitumen for a couple of days, then we tried to run diesel for a couple of days, and then we tried to run jet fuel for a couple of days through a pipeline that stretches over thousands of kilometres?

[Peter Boag]

I can't talk to all of the necessary details, not being a pipeline expert, but first I would clarify that we do have two kinds of pipelines in Canada. The pipelines that ship crude are distinct from the pipelines that ship finished products. We do not mix crude and finished products in the same pipelines.

We have a number of pipelines, particularly in eastern Canada, that ship finished product from refineries to major market centres. The products that go through those pipelines are different on a day-to-day basis, depending on the demand and how the pipeline schedule works. You cannot ship gasoline and diesel at the same time. You ship gasoline, and then you need to ship a load of diesel after that.

Certainly the longer distances you try to do that, the costs do increase. I think that comes back to the principal discussion we had earlier this morning, that because of the costs and the inefficiencies involved in shipping finished product over long distances, generally the refineries have been located closer to market.

As for the costs, I don't know what would be the specific incremental costs.

[The Chair, Conservative, Leon Benoit]

Thank you, Mr. Calkins.

Monsieur Gravelle, you have up to seven minutes. Go ahead, please.

[Claude Gravelle, NDP, Nickel Belt, ON]

Thank you, Mr. Chair.

I'd like to thank all of the witnesses for coming out here today.

My question is for the assistant deputy minister. I want to refer to a recent CBC interview. The Prime Minister acknowledged the issue of energy insecurity in our country. That was in an interview he did with Peter Mansbridge, I believe.

He said, and I want to quote him, that “...on a certain level.... It does seem odd,”—that we are moving oil out of western Canada to the United States or Asia when a good chunk of Canada itself does not have domestic oil—“and I do think there are people out there in the marketplace looking at dealing with that particular sensitivity or insecurity.”

Can you comment on that issue of insecurity for our country and what the Prime Minister might be referring to, in terms of what is happening in the marketplace to address this? Has your department studied this insecurity issue?

[Mark Corey]

Thank you, Mr. Chair.

I think you could answer that really at two levels. What the Prime Minister I believe is referring to is the fact that as oil production ramps up in western Canada, you will likely see the market respond. In fact we're already seeing the market starting to respond.

Line 9, which is an Enbridge pipeline that runs from Sarnia to Montreal, was originally built to go from west Sarnia to east Montreal, bringing western crude to the Montreal market. In the 1990s, for economic reasons, it was reversed. It was bringing imported crude all the way down to Sarnia.

What you're seeing now is that Enbridge, for example, has applied to reverse line 9 as far as Nanticoke, which is just west of Toronto. The idea is that, again, they would be bringing western crude more into the Ontario market and the refinery specifically at Nanticoke. There has been speculation in the media as to whether or not they will eventually reverse it all the way to Montreal, but that's a decision for the company to make.

So you'll probably see some of those adjustments happen. As well, Canada is an international trading country. We also seek energy security at the international level. This is the reason why we're a member of the International Energy Agency, which is a grouping of countries that both produce and consume—largely the consuming countries. These countries band together. We monitor the markets very closely. We have mechanisms where, if there are production shocks, for example, we respond as a group. We also rely on the collective approach to energy security internationally through the International Energy Agency as well.

So I would say it's probably those two things that are at play.

[Claude Gravelle, NDP, Nickel Belt, ON]

Thank you.

My second question is also to you, Assistant Deputy Minister.

The minister, when he was here for estimates, used figures of anywhere from $7 billion to $16 billion for new refineries. Can you break down the costs for a refinery? And do you have an estimate of the lifetime economic output of a new refinery and the government revenues compared with a pipeline?

[Mark Corey]

Mr. Chair, I was wondering if I might actually refer this to Peter and ask him if he could talk more about the costs of a refinery, as really that's in the private sector and that's what they do.

[The Chair, Conservative, Leon Benoit]

Mr. Boag, go ahead.

[Peter Boag]

Certainly refineries are a very capital-intensive business. You are talking about anywhere from $7 billion or more to build a new refinery. In our presentation we talked about the kind of capital investment that has been required over the last 30 years in Canada to maintain a viable and competitive refining sector. That's about $40 billion on an annual basis right now. The investment requirement to sustain and maintain our competitiveness is about $3 billion per year.

[The Chair, Conservative, Leon Benoit]

Okay, go ahead.

[Carol Montreuil, Vice-President, Canadian Petroleum Products Institute]

As a complement, building a refinery is a 40-year endeavour, as a minimum, in terms of looking at returns over a long period. An economist would tell you that by and large this business is roughly an 8% to 10% business. You are looking, in terms of a return, at 10% on average over a long period. Given how capital intensive the business is, you have to think about it twice before spending that kind of money.

[Claude Gravelle, NDP, Nickel Belt, ON]

All right. This is the second part of my question for the government. Can you give us a breakdown of the government revenues of a refinery as compared to a pipeline?

[Mark Corey]

Mr. Chair, we would have to get back to you with that. I can tell you that at the macro level, for example, the refining industry in 2009, according to a recent Conference Board report, contributed $2.5 billion to the economy and provided the direct employment of 17,500 workers. As an aggregate, it's an important part of the economy. We'll have to get back to you with specific numbers.

[Claude Gravelle, NDP, Nickel Belt, ON]

Can you provide us, now or later, with a breakdown of the Canadian and foreign ownership of the oil sands—dollar and percentage investment of the oil sands by country and company?

In addition, what is the current level of Chinese involvement in the oil sands? If you can't give that to us now, can you give it to us later?