Environment Committee on May 13th, 2009

[The Vice-Chair, Liberal, Francis Scarpaleggia]

In connection with a point Ms. Duncan made about groundwater monitoring and the study of groundwater, I have a report here from February 5, 2004. It's an application for an oil sands mine, bitumen extraction plant, cogeneration plant, and water pipeline. It's from Shell Canada. Part of the report says these are the views of AENV, which I suppose is Alberta Environment.

[Ian Mackenzie]

Yes.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

It's the reaction to the application. It says that with respect to project-specific considerations, AENV indicated that a regional groundwater study on the PCA was not necessary, but that the information provided by a regional study might be useful. What does all that mean?

[Ian Mackenzie]

I see that my earlier guess was incorrect now that I understand the context. PCA in that context means Pleistocene channel aquifer, which is an aquifer that runs through the eastern side of the oil sands area and up through many of the proposed mining operations. The quality varies from almost potable level to very poor quality. It is similar to a deeper aquifer called the basal aquifer.

In relation to the study you're quoting, I believe at the hearing surrounding the environmental impact assessment there was talk about potential influence of seepage into that Pleistocene channel. In terms of follow-up actions, I do remember the recommendation that there be additional monitoring of that aquifer, and I believe Shell does have required groundwater wells in that aquifer, as do many of the other operators.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

I have just one more point.

If I'm not mistaken, one of the things Dr. Schindler was saying in terms of access was that he didn't have access to the methodologies being used by RAMP. To get access, you had to be a contractor or a researcher working on a RAMP project, and he's not a member of RAMP. If I'm not mistaken, that was one of the points he made.

If you want to respond to it, you may.

[Fred Kuzmic]

Sure, I would like to. Thank you very much for the opportunity, and it relates back to something Ms. Duncan had mentioned.

One of the peer review comments was that we didn't have a design and rationale document. That document and a description of how the program was conducted wasn't available to the general public. Since then, that manual has been put together. It is available on the RAMP website for people to look at. How the study was put together, what monitoring activities are under way, and how things are being analyzed and presented in the technical reports is publicly available information. That document is updated on an annual basis, and, again, it is available.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

Thank you.

We'll move on to our next panel. We're thinking that perhaps at the end we could ask questions to both panels. I imagine you'll be remaining in the room.

Thank you very much. I think your document is very rich, and it will be very useful to our researchers in terms of drafting the report.

There will be a short pause before continuing with our next witnesses.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

I would ask that members resume their seats and that our next round of witnesses take their seats.

I imagine all witnesses will be presenting. I would ask that presentations be limited to five minutes so that we can get more questions in.

Without further ado, I will ask for the first witness, Mr. Fordham, to begin.

Thanks again, Mr. Fordham, for that tour on Monday. It was excellent.

[Chris Fordham, Manager, Strategy and Regional Integration, Suncor Energy Inc.]

Good. I'm glad you enjoyed it. I certainly enjoy showing off what we're doing.

This morning I'm going to be speaking more specifically about Suncor. We saw most of the major projects in the region on Monday. Specifically, I want to talk to you a bit about what we're doing with water, how we're using it, and how we're trying to make more efficient use of the water we have.

We are currently operating with the same water licence we got when Great Canadian Oil Sands started in the late 1960s. Since that time, we've more than quadrupled our production, and with our Voyageur project we're going to double it again, all with the same water licence, so our water efficiency has increased significantly over the years. Once we've achieved this doubling of production, we're going to continue to explore further opportunities for water efficiencies and continue to reduce our overall environmental impact.

How are we going to do that? Well, we're looking at a number of options. We're looking at recycling and reusing waste water streams and improving our waste water quality so that we can either reuse more of it or provide better quality in what goes back to the river, which will improve our CT performance. I'll get to what CT is shortly, but that also will free up more water for use in the plant. We are also looking at new tailings technologies, such as dry tailings.

I don't want to get too hung up on this graph. It's a little busy. The graph shows that water gets used in every aspect of our operation. We have a mining operation and a bitumen upgrading operation. We have energy services, which produce steam and power. As well, we have a large in situ project, named Firebag, that we couldn't fly over on Monday, unfortunately, because it was fogged in.

Water is used in every part of our operation. What I would like to draw your attention to, though, is on the little chart at the bottom on the left-hand side. It shows our water use efficiency on a cubic-metre-per-cubic-metre basis or barrel-per-barrel basis. Once we have Voyageur up and running, we'll be using about 1.67 barrels of water for every barrel of oil produced.

This is what our water use efficiency and total water use look like over the past few years. We've seen a 30% increase in our water use efficiency and overall water use. We're currently licensed to 59.8 million cubic metres per year from the river. We've used less than 85% over the last three years, and we expect to continue reducing that going forward. Our total use is less than 0.5% of the average annual flow. We heard talk of average annual flow in the river. That's really what we saw in the river on Monday; it was about the average annual flow.

We did have a little bump up last year. We had some plant reliability issues, which we've gotten through; now our production's back on track, and so is our water use.

One of the processes we use at our mine site is consolidated tailings, or CT. CT is a process that was developed through a multi-industry research cooperative effort back in the mid-1990s. It takes a regular tailings stream and densifies it; it takes out a bit of the water, adds some fine tailings out of the tailings pond, mixes that with gypsum, and pumps that slurry out to the pond.

The difference between CT and our normal tailings is that when normal tailings get to the pond, the sand settles to the bottom and the clay stays in water suspension above it. They're very separate. With CT, the sand and the clay stay together. The clay structure collapses because of the gypsum, freeing up water. It consolidates much more quickly and frees up the water. When it frees up the water, you can end up with a dry, trafficable surface much more quickly.

We started with CT back in the mid-1990s. It did take a number of years for us to get it sorted out. It's a very easy process at a lab scale, when you're mixing litres or several litres of fluids together, but when you're doing it at 60,000 gallons a minute, it takes a little more effort to get it right. However, you can see that over the last three years our efficiency with CT has increased significantly. Probably the maximum we can get to is about 76%. About 76% of the time, you can make good CT.

Why is it only 76% of the time? Surprisingly, one of the issues is sand availability. You'd think perhaps with the amount of sand that we mine every day, several hundred thousand tonnes, we would have lots of sand, but in fact a bunch of that sand gets used to build the dikes that contain the CT ponds. We have to do that in conjunction with making CT, so 76% is the about the most effective we can make CT. Producing it at that rate will allow us to use up our mature fine tails inventory.

What else are we doing? We have a number of projects. We're looking at putting in another cooling tower so that we'll be using less water from the river for cooling. We're looking at recycling water to our cokers. Water right now ends up in the tailings ponds; we're going to try to recycle it so that we're not using fresh water, or other waters, to do the coke cutting. We're looking at treating and recycling some of the waste water that currently goes to the river, so that we can use different streams in our boiler feed-water or have better-quality water return to the river. Those projects, in total, would be about $100 million.

There are two other aspects I want to touch on a little bit, dry tailings and pond reclamation.

Once you reclaim a pond, you no longer have that fluid inventory and you can begin to return that land back to what it was before the mining operations were there. We're going to have the first tailings pond in the region reclaimed by next year, pond 1, and we're working on techniques to get ponds 5 and 6, our first consolidated tailings, reclaimed by 2019.

Another area we're exploring is dry tailings. We're looking at a number of techniques there to try to get the water out of the tailings, to free it up so that we can recycle it, reuse it, and produce drier landscapes.

This is our mature fine tails drying, one of our trials. The picture on the right is our starting material, which is mature fine tails that have had some sort of either chemical or mechanical treatment applied to them to make them a little thicker and to increase the solids content. Material gets spread on a beach, where it dries. Over the course of the winter it freezes and cracks, and the water moves into water lenses. When it thaws in the spring, the water runs off, and you're left with a material much like you see in the bottom right picture. It goes from yoghurt to something that's about the consistency of coffee grounds.

In relation to reclamation, this is pond 1. We flew over this on Monday and had a look at it. You can see the progression over the past couple of years. One of the reasons it appears that the infilling doesn't move very quickly is that most of the infilling happens below the water surface, so you don't see any difference.

We saw our first benefits from the efforts of our infilling back in the summer of 2007. You can see a little tiny white beach there in the top of the summer of 2007 picture. By summer 2008, a large area of the infill was above the water level. That's fall 2008. Then you saw it on Monday, and there's an area that still has fluid in it. That fluid is being removed and sand is being infilled into that pond. Next year we will have soil and revegetation materials on it, and by 2020 it'll look very much like the landscape surrounding the mine itself.

Thanks very much. I'd like to pass it over to Mr. Duane.

[The Acting Chair, Conservative, Blaine Calkins]

I'll just give a reminder to please stay on time. We're trying to stick around the five-minute mark, or a little bit more.

Mr. Duane, please start.

[Calvin Duane, Manager, Environment, Canadian Natural Resources Ltd]

Bonjour, et bienvenue a Calgary.

I'm going to talk about three topics that are fairly exciting for Canadian Natural in terms of water and water use in the oil sands.

The first one I want to talk about is our new technology of carbon dioxide use in tailings. It is much the same as what Mr. Fordham talked about in reference to CT usage; we use carbon dioxide to achieve much the same results.

As you can see, in our case we use carbon dioxide to create NST, non-segregating tailings. The picture shows graphically how the material has settled into the bottom part of the cylinders, which essentially is the fines settling out of it. This reduces our use of fresh water and gives us a smaller tailings footprint. Our tailings are solidified sooner, which gives a reclamation surface. It reduces our carbon dioxide emissions by approximately 11%, and overall, through an integrated process, it just saves a lot of factors together.

Borrowing from Mr. Fordham's slide showing you his technique of demonstrating the process, I'm showing a very similar slide so that you can see the similarities between the two processes. We had a thickener of tailings, a carbon dioxide injection to produce thickened tailings or, in our case, non-segregating tailings.

The second item I want to talk to you about is water storage. It's a new feature in the oil sands development, but it's now a common practice for all new projects to develop water storage on-site. We have developed a 1.7 million cubic metre storage facility of raw water from the Athabasca River. This provides us with approximately 30 days of operation, assuming there are 1.3 metres of ice on it.

It was designed three years prior to the IFN coming into place, so it was not the IFN that drove us; it was actually our own recognition of the issue of managing water properly. We made sure it was operational two years prior to the operation of the Horizon project to ensure that we had that water while we were coming into operation, not afterwards. It is the best management practice, and it was designed to meet stakeholder and aboriginal concerns.

The third and last item I want to talk to you about is developing a compensation lake for the fisheries habitat loss. It was a Fisheries and Oceans Canada requirement to do this, and we have done so. We have created a lake, and we filled it in May 2008. To date it has exceeded our expectations. The water quality exceeds what we expected it would be, and already we have fish in the lake; five of the eight species we wanted in this lake are there presently.

The lake replaces the lost habitat in both the Tar and Calumet rivers. It replaces it at a ratio of 2:1, so for every one unit of habitat lost, we replace two into the lake. This design was based on four years of intensive stakeholder consultation and scientific workshops. We brought in science and we brought in traditional environmental knowledge. We brought in a number of factors, and this met the federal requirements under Fisheries and Oceans Canada.

Finally, I wanted to provide you with some statistics on the lake. They are there for your interest.

This summarizes the three topics I wanted to bring to your attention, and I believe I've done so within your timelines.

Thank you.

I'll pass it over to Mr. Fox.

[The Acting Chair, Conservative, Blaine Calkins]

Go ahead, Mr. Fox, for five minutes, please.

[Matt Fox, Senior Vice-President, ConocoPhillips Canada]

I'm going to discuss specifically the water use and the SAGD, steam-assisted gravity drainage, aspects of the oil sand business. I hope to leave you with three pretty clear messages: that SAGD uses only non-potable sources of water from deep aquifers; that SAGD companies are moving more and more towards saline water use as time goes on; and that the technology is likely to significantly improve water use in SAGD over the coming years.

First of all, I understand that you didn't fly down to Surmont. This slide, nonetheless, shows you the overall footprint of the Surmont phase one development. You can see the central facility in the front of the picture and the two well pads up towards the top of the picture. That's the overall footprint.

The next slide is a picture of the processing facilities. The only reason I included it is that it shows that the processing facilities for SAGD are mostly dominated by water treatment. SAGD, as you know, is steam-assisted gravity drainage, whereby we inject steam into the reservoir to melt the bitumen. That requires a significant amount of heat; and when you're turning it into steam, it also requires that clean water be used in the process. A lot of the process is dedicated towards cleaning up the produced water, so we can reuse it—cleaning up the water we get from the deep aquifers, because it's not potable or clean enough to put through a boiler, and then processing that water through the plant.

The next slide shows at a high level how the water process works in SAGD. First of all, the thinner blue arrow coming up is our make-up water, the water that we take from the Grand Rapids formation. It's non-potable, but is classified as freshwater because it is less than 4,000 parts per million in dissolved solids; it has about 2,500 parts per million dissolved solids.

If you look at the schematic on the left-hand side of the chart, we turn 2.5 barrels of this water into steam in the plant and then inject it into the reservoir. This process recovers one barrel of bitumen. That water is then produced back with the bitumen, and 90% of it is treated and then recycled. Then a quarter of a barrel is disposed into the deep formation you can see there, the Fort McMurray formation. Then that quarter of a barrel is produced from the Grand Rapids sand and is mixed with the 90% that's recycled, and the process starts again. So we use about a quarter of a barrel of water from the aquifer for every barrel of oil or bitumen that we produce.

We also produce water vapour of about a quarter of a barrel of water, associated with the combustion process. That's what the top of the diagram shows. So we actually produce into the hydrological cycle the same amount of water we take from the aquifer, if you follow me. I'll get back to that on that last slide, when I talk about technology.

The reason we're using what's classified as freshwater is that's all we can find near the Surmont lease. It's what's underneath our lease. So we've been exploring over the past five years or more for more saline sources of water, trying to find water that would be in the 4,000 to 10,000 range of salinity. We've gone as far as 60 kilometres away from the plant, and we recently found some sources of water that would be in that 4,000 to 10,000 range. But the water is quite a significant distance from the plant; it could be easily 30 kilometres from the plant we'd have to pipe that water back to Surmont, and treat it and then put it through the process. But we are actively exploring for more saline water so we can reduce the use of the water from the existing aquifer.

On the final slide, as far as the future is concerned, our future projects have been designed for 95% recycling rather than 90%. Of course, when you go from 90% to 95% recycling, it halves the amount of water you need to use. As I said, we're looking to increase the use of more saline water and we're actively exploring for that. We've spent $70 million over the last five years just exploring for saline water to use in the plant.

We have done a huge amount of research—at least $300 million—and will do between $300 million and $500 million of research over the next five years on oil sands activity.

One of the main focuses is to adjust the steam-oil ratio, because that reduces the cost of buying gas, reduces the greenhouse gas emissions, and reduces the water emissions. There are several encouraging technologies for adjusting steam-oil ratio. One example is injecting solvents with the steam.

We are also doing research into how to economically capture the water from the combustion, that quarter of a barrel I spoke about earlier. If we can do that in an economic way, we could virtually eliminate the need for any external water source for SAGD operations.

[The Acting Chair, Conservative, Blaine Calkins]

Thank you very much, Mr. Fox.

Mr. Scott, please go ahead.

[Michel Scott, Vice-President, Government and Public affairs, Devon Canada Corporation]

Thank you.

In a nutshell, our project, which is a steam-assisted gravity drainage project as well, is just about the same thing as was described, with the one key distinction: we use strictly saline water.

Good morning, ladies and gentlemen.

I work for Devon Canada Corporation, and we are very proud of what we've have accomplished with regard to water and other issues. I'm also very pleased that we've been given the chance to speak to you.

I will repeat this; don't panic.

Thanks, everybody.

Ladies and gentlemen, at Devon we're very proud of what we've accomplished at our project in terms of how we've treated water and in terms of other aspects as well. It's a great opportunity for us to talk to you.

First of all, our project is located about 140 kilometres south of Fort McMurray. I'm sure you didn't fly through there. We're located about 15 kilometres south and east of a little community called Conklin. We are still located in the regional municipality of Wood Buffalo, and we pay municipal taxes to them. I only make that point because in effect we draw most of our services and quite a few of our people out of Lac La Biche, so we really don't put any pressure on Fort McMurray.

So that you remember this presentation, I'm going to enumerate the three main points. First, we use no surface water at Jackfish and no drinking water. Second, we recycle 95% of our water. Third, we have no tailings ponds like in the mines.

I'm going to summarize this very quickly.

There are three key points for Jackfish. First, we use no fresh water or surface water in our operations, with the exception of potable water for human consumption. Second, we have a high recycle rate, upwards of 95%. Third, we do not discharge or have tailing ponds on our sites. We don't withdraw from or discharge to surface locations, and when we do draw water, it's from a deep saline aquifer located about 300 metres below the surface.

In the photo here, although you can't see it very well, we have three small ponds. One of those is called a blowdown pond. That's a pond that we discharge water into when we're trying to ramp up our operations and heat up the operations or cool them down, and then once we're done, we can draw that water back into the process. We also have a sewage pond used to support our people's camp operations, and we have another pond, called a retention pond, that simply captures the surface waters.

Concerning the next slide, you've heard Matt talk about the steam-oil ratio. We're running at about 2.65 right now, but of course we're recycling most of that. Our target for the near future is to achieve a 2.5 ratio, but we are focusing on trying to reduce that even more.

Another thing I'd say about SAGD is that the surface impact or footprint related to this type of activity is quite small relative to even the conventional type of oil operations. We're going to produce 35,000 barrels of oil there daily off four pads, essentially, which have more or less seven wells each. Each well is going to produce about 1,000 to 1,500 barrels. For comparison, an average conventional oil well in Alberta produces less than 20 barrels a day. So there are some benefits from that aspect as well.

Let me tell you, this isn't an accident that we're using saline water at Jackfish. We have a commitment and a policy in the company that we're going to minimize the use of fresh water. We had consultations with our stakeholders, and we do it not just in the oil sands, but in everything we do. When Jackfish came along, we applied this policy and put it in action. Of course we had to find the saline water as well, and we had to deliver on that promise. We too had to drill a number of wells, but we were fortunate and we did find it.

From our standpoint, this was the right thing to do. We wanted to develop the oil sands, but we wanted to do it in an environmentally friendly way.

Matt just showed you a slide similar to this one as well. There are essentially four parts to this plant, from oil separation to oil storage, but there is also a big water treatment component, and of course we have our steam generators. The bottom line is that about half of the capital that goes into this plant is related to water recycling. We tend to think of this as a water recycling plant that enables us to reuse the water.

The other feature, which is not shown on this slide, is the extensive monitoring program that surrounds our property. We have 12 wells that monitor a dozen or so various aquifers. This information is collected and reported to the regulatory bodies. If any change in temperature or pressure were to occur, we would know what was going on and we could take corrective action.

You've seen various versions of the next slide. The only point I'd like to make is that in addition to the monitoring that goes on, above the Fort McMurray formation where we produce our oil there is a buffer of over 200 or 250 metres of cap rock that sits above the formation and essentially seals the formation off from any of the aquifers closer to the surface. That distance, by way of comparison, is roughly the size of the Calgary Tower, or two Peace Towers, in terms of height.

In terms of the road ahead, from our standpoint “good” isn't good enough, and it's particularly true with water. We have a saying in the company that governments grant us permits, but the communities grant us permission. It's very important to listen to what folks want, to try to manage that, and to be as good a neighbour as we can possibly be. We're seeking to do more, and we're directing our activities to that end.

I know you've visited the oil sands, but if you ever have the inclination or if you can make it--any one of you or all of you--you are invited to our site.

In closing, I would like to thank you sincerely for the opportunity to make this presentation. We would also be very honoured if some of you would come and visit us.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

Thank you, Mr. Scott.

There's only one presenter left.

Mr. Wright, go ahead please.

Go ahead, Mr. Wright.

[John D. Wright, President and Chief Executive Officer, Petrobank Energy and Resources Ltd.]

Thank you very much, Mr. Chair and members of the committee. It's a pleasure to be here today.

I'm here representing Petrobank Energy and Resources. By way of background, we operate throughout western Canada as well as in Latin America, and have great exposure to both the regulatory and environmental challenges of the heavy oil and oil sands industry throughout those regions, as well as some of the global implications of that.

Within our heavy oil group, we maintain a technology division, which actually owns some of our proprietary intellectual property. I'm going to talk about some of that today. But the focus of the company in particular is to find global solutions to the heavy oil challenges faced not just in Alberta but throughout the world in all the heavy oil basins.

In terms of location—this might help with Michel's presentation as well—we operate directly to the west of the Devon Jackfish operation, at our Whitesands project area. This is in situ central. That tiny map shown on the right actually represents about 600,000 barrels a day of planned and approved projects in one very tiny part of the oil sands, all of which will be derived by in situ means, none of which is accessible through conventional mining methods.

What we're doing is something radically different from anything that has been tried before. Our Whitesands projects implements the THAI process. I could go on for hours about how this works, but in a nutshell, the acronym, THAI, stands for “toe to heel air injection”. Rather than using steam or combusting natural gas on the surface, we drill a horizontal well at the bottom of the reservoir and a vertical well at the toe of that horizontal well, and we inject air, atmospheric air under pressure. The air contacts the bitumen in situ and generates an oxidization reaction that will have temperatures ranging between 700°C and 1,000°C in the combustion zone. That heat mobilizes the oil, actually has the effect of partially upgrading the oil in situ and drops out a percentage of the coke, and all the oil flows naturally to the surface.

In one little slide I can show you the highly underwhelming impact of our surface facilities. There is no water treating facility. There are no steam-generating facilities. It's a simple oil battery and air compressor system.

The key to THAI is more than just the fact that we don't use any fresh water in our process. We actually produce a usable water stream. We've eliminated the use of natural gas. We've increased the recovery rates, with about half the greenhouse gas emissions of any of the other processes available today. Because we have a partially upgraded oil product, we actually have simplified our operations on the surface, and of course, a much smaller surface footprint means that the total overall impact of the process is very minimal.

The best way to characterize the oil that comes out of the ground is that the bitumen that's derived from most processes is like the bitumen shown on the left in our slide. It's actually heavier than water and does not pour at room temperature. On the right in our slide, you'll see our THAI upgraded oil, which has a viscosity that's pipeline-able at surface conditions and is in fact about 4° API to 5° API lighter than the in situ bitumen. That oil is about a 12° API crude.

The importance of having a light oil product in the heavy oil world means that your process becomes much simpler. Our oil floats on the produced water component, which means we have an easily separated emulsion, allowing us access to a very clean produced water stream that has some great characteristics.

When you compare the produced water that we take off our separators, we actually have very similar water characteristics to the water that Devon is taking from the aquifers directly adjacent to us. In fact, our produced water would pretty well match their feed water for their process and would provide another source of water for other industrial uses as well.

The last thing I might emphasize about the water that's produced is that, from the secondary condensing, we actually condense a purer steam component, which means we condense, effectively, distilled water from our process, which has direct use in power generation applications and other applications.

To finish it all off--we all seem to have pictures of this--this slide shows what a typical surface application for our well sites would look like.

The final slide slows the minimal surface impact we would have for a process facility that would be capable of up to 100,000 barrels a day of commercial oil production.

That's our story.

[The Vice-Chair, Liberal, Francis Scarpaleggia]

That was very interesting, Mr. Wright.

I believe we can now move on to our round of questioning, which Mr. Trudeau will open.

[Justin Trudeau, Liberal, Papineau, QC]

Thank you.

Mr. Fordham, when we flew over with you on Monday, you pointed out the Bison site, which was the first reclamation or the successful project of returning to the land what we had.

What was the total cost of reclaiming that particular site?

[Chris Fordham]

That was a Syncrude site, and I don't have those numbers available. I'm guessing that we could probably find them for you, though.

[Justin Trudeau, Liberal, Papineau, QC]

In one of the testimonies yesterday, someone mentioned that site was one of the easier places to reclaim because of environmental, geographical, and geological factors. It was done first as a showcase of what could be done because it was more easily done than the others. Is that a fair assessment?

[Chris Fordham]

The industry has done an awful lot of research into reclamation over the years. I'm not exactly sure of the time that one took, but it's certainly evidence of successful reclamation. We've reclaimed a number of other sites over the years, and each of them probably had their own individual challenges. But we're certainly learning how to make it work.

[Justin Trudeau, Liberal, Papineau, QC]

There's one other comment that struck me when we flew over Kearl Lake. You mentioned that it's a shallow lake that freezes right through and that the compensation lakes you'll be making are deeper. Certainly on the surface, I thought that seemed to make sense, although subsequent commentary from some of our native elders and chiefs was that it might not necessarily be a good thing.

My concern is that the lakes to be reclaimed are deeper because they were created through mining processes. Have there been a lot of studies done on what kinds of habitat the reclaimed lakes will create in the long term? I guess I'll turn to Mr. Duane afterwards, as he has an extensive slide on this.

[Chris Fordham]

Again, there's been a fair amount of research in that area over the years. The specific lakes I referred to in the helicopter are part of the Imperial Kearl project, and I can't speak specifically to the nature of those lakes beyond what we talked about in the helicopter.

I do know that if you are providing compensation as part of the DFO approval, then that compensation has to support fish habitat. Making it shallow enough that it freezes to the bottom probably won't achieve that.

I'll let Mr. Duane speak further to that.

[Calvin Duane]

We built a compensation lake and it's functioning, but you're absolutely correct about the importance of shallow areas. In fact, 30% of our lake is shallow just to provide for that value. But to ensure that they last over the years and provide habitat, they need the deep components to them as well. So our lake has a component that's less than five metres deep, but it also has a component that's about 20 metres deep, which provides different habitats. All of those things are important.

We developed our lake, and I assume Imperial will do the same with theirs, by working with the stakeholders to find out how to match it. I can't show you the pictures of our lake, because the aboriginal people don't like them to be shown, but we did a blessing of our lake. They were out there and they actually contributed to the lake. We continue to meet with them and they're actually working with us to design the lake and the vegetation around it. We're building a gathering place for them. We've already done 80 hectares of reclamation around the lake.

So we do work with the communities, very much so, on these compensation lakes.