:
Good morning, Mr. Chair and panel.
I'd like to express our appreciation for your taking the time to listen to us, for inviting us here, and for the time you spent in Fort McMurray viewing our operations and the oil sands.
I'm Don Thompson, president of the Oil Sands Developers Group. I'd like to start by introducing our panel. Stuart Lunn is with Imperial Oil. Mr. Ian Mackenzie is with Golder Associates. Mr. Fred Kuzmic is with Shell Canada. Mr. Greg Stringham is with the Canadian Association of Petroleum Producers.
Water is clearly a critical aspect of the production process used for bitumen extraction and recovery, which we'll talk to in a bit. In reality, Canada’s oil sands use a very small percentage of available water, and the water used is highly regulated. For example, oil sands use is currently less than 1% of the mean annual flow of the Athabasca River, and there are procedures and processes in place that cap that withdrawal during low-flow periods
Regulations also do not permit the release of any untreated oil sands process-affected water, and ongoing aquatic monitoring has not shown impacts to the lower Athabasca River aquatic ecosystem associated with oil sands development.
Oil sands projects recycle a high percentage of the water they use, ranging from 80% in surface mining to over 95% in the in situ industry. In fact, the in situ side of the oil sands industry is shifting increasingly from the use of fresh water to the use of saline water, and of course none of that is from the Athabasca River.
The other reality is that pumping water, storing it, and treating it is a key cost of production. We have every incentive to minimize our water use, and that is important to the economics of oil sands production.
Recently there have been calls on both sides of the border to strike a balance between energy, environment, and economy. In my view, that balance is being struck today in the oil sands.
On the environment, local air quality is excellent and is being managed well. Greenhouse gas emissions are low and are a small percentage of Canadian and global totals. The use of water is being reduced through improved and increasing technology. As I've already mentioned, a high percentage of the water we use is recycled, and the in situ industry is moving increasingly to using non-drinkable water.
In terms of the land, minimization of impact has always been a watchword. Of the 530 square kilometres that have been disturbed over 40 years of surface mining, 65 square kilometres are currently under active reclamation. Advanced technology is being developed and innovation is being applied to all aspects of environmental management.
The reality is that the oil sands are a key strategic Canadian resource. They provide today, and will provide increasingly in the future, strong security of supply to Canada. They are a major component of this country's future energy mix.
On the economic side, oil sands economic impacts are felt across this country. Between 2000 and 2020, oil sands development has the potential to generate at least $885 billion in total economic impact, with $123 billion in royalty and tax revenues for Canada's federal and provincial governments. It's important to understand that for each permanent oil sands-related job, nine additional direct, indirect, and induced jobs are created in this country.
Yesterday I was in Drummondville, Quebec, where I met with the Quebec branch of the Canadian Manufacturers and Exporters and a number of steel metal fabricators, mining equipment providers, and the like that support this industry. In fact Suncor, which presented with me, demonstrated that they had 199 vendors in Quebec and almost $200 million of expenditures last year.
It's also important for people to realize that my members have workforces on their sites from coast to coast, from the far east to the west, and the oil sands represent people and industries coming together in Fort McMurray. The oil sands are a national endeavour.
On how oil sands fit into the future energy mix, you should know that global economic growth will require more energy of all kinds. In North America, energy use grows by about 1.5% a year, driven by population growth, lifestyle enhancements, and offset to a small degree by efficiency. Despite growth in the use of renewables and other forms of energy, oil remains an important long-term component of the global energy mix.
We will be needing all forms of energy because of growth in global population. But the reality is that oil sands resources are a vital part of the global petroleum supply. In Canada we are privileged to have the second-largest crude oil reserves in the world--second only to Saudi Arabia--at 178 billion barrels. But the reality is that 97% of those, or 173 billion barrels, are in the oil sands. Stated another way, in other countries and locations where crude oil is accessible, a full 87% of the world's known oil reserves are currently in state-owned or state-controlled locations held by countries such as members of OPEC, Russia, and the like. Only 13%, or one barrel in six, is openly accessible to international oil companies, and half of that is in Canada’s oil sands.
Our conventional production is declining by about 4.5% per year and will continue to do so. That gap has to be filled by oil sands and is being filled by oil sands. But the other reality is that the economic turmoil in recent times has flattened that line. You will see in the next forecast that the growth rate from 2008 to 2012 will flatten. So oil sands are critical to this country's future energy security. Oil sands exports will also be a key component of the balance of payments future of this country.
I know that on your tour you witnessed both kinds of oil sands production technologies, so I will not dwell on that. I'm sure you saw mining, trucking, and shovel operations; however, I draw your attention to the fact that 80% of the reserve base I spoke of must be produced by in-ground or in situ technology where there is no mine, no tailings ponds, and no water from the Athabasca River.
With that, I'll turn the floor over to Mr. Lunn, who will talk about water quantity issues.
:
I'd like to spend a little bit of time talking about the perspective of water availability in the province of Alberta, and then I'll talk specifically about water use in the oil sands industry, both in surface mining and in the in situ industry.
Each year in the province, approximately 130 billion cubic metres of water flow through the rivers of Alberta, and 85% of this water flows north. By far the largest rivers in the province are the Peace and the Athabasca rivers, joining to become the Slave River, leaving the province to the north. In contrast, in the province 88% of the water demand is in the agricultural areas and the major population centres in the south half of the province.
All the oil sands production is in the northern basins. The mining oil sands are all within the Athabasca River basin, and in situ oil projects are distributed among the Peace, the Athabasca, and the Beaver river basins.
Of the 130 billion cubic metres on average available in the rivers of Alberta each year, the Alberta government has licensed or allocated just under 10 billion cubic metres per year to all sectors within the province. The oil and gas industry accounts for about 7% of this provincial allocation--on here, the yellow portion of the bar--after the large sectors of agriculture, commercial, and municipal use.
Most of this allocation, unlike the other sector use, is allocated or licensed for oil sands mining in the Athabasca River basin, about 70% of that 7%. The rest of the oil and gas sector uses the remaining water, and comparatively small volumes are used for in situ oil sands production.
It's noteworthy that criticism of oil sands water use often fails to recognize that the use is in the northern basins, where the water supply is much more plentiful and water use is a small percentage of natural supply.
Focusing on that with a little more detail, oil and gas allocations represent 2.2% of the allocations of the natural flow of the Athabasca River, 0.04% of the natural average flow in the Peace River, and 3.7% of water availability in the Beaver River basin. It's worth noting that the actual water use is often less than the allocation, but concerns and water shortages in central and southern Alberta have led to misperceptions about water supply in the north for the oil sands.
If you take a quick look at the chart, there are three bars. The axis represents billions of cubic metres of water. The blue bar is the average natural supply in the river basin, the red bar represents the total amount of water allocated in that basin for use in all sectors, and the yellow bar represents the amount of water allocated for use in the oil and gas sector. What we can quickly see is that the allocations in the south half of the province, in the North Saskatchewan and South Saskatchewan River basins, represent a large percentage of natural supply, some 30% of the North Saskatchewan and nearly 60% of the South Saskatchewan.
In comparison, including forecast growth in the oil sands industry, the Athabasca, Peace, and Beaver river basins will remain among the least utilized basins in the province.
I'll now focus on the oil sands mining industry. Over the last several years, the Oil Sands Developers Group has been working on forecasting how much water might be required from the Athabasca River. Both lines on the chart represent aggressive growth cases, the purpose being to try to determine how much water might be required from the river if projects go forward as envisioned and if future projects go forward as envisioned.
The lower case represents 2.5 million barrels of oil per day, and the second case is 3.5 million barrels of oil per day, which is approximately four times current production rates. The left axis shows the absolute amounts of water being withdrawn from the Athabasca River, and the right axis shows the percentage that this withdrawal represents of the mean annual flow at Fort McMurray. We can see for those two growth cases that the industry use of water is expected to rise to between 10 and 15 cubic metres per second, which represents about 1.5% to 2.5% of the flow of the Athabasca River. We also see that it peaks, in the most aggressive case, at around 16 cubic metres per second, or just under 2.5% of the mean flow. And I'll be talking about that number again.
So why is there so much concern about water use from the Athabasca River, given the very low percentages of water that are allocated, and the low percentages of water that are being used now, and will be used in the future?
This is mostly because the Athabasca River is ice-covered for five to six months per year, and the winter flows are about 10 times lower than the open-water flows. Also, the Athabasca River's flows are not regulated by dams. The concerns very much focus on withdrawals during low winter flow weeks, and especially in dry periods during those low winter flow weeks.
It's worth mentioning that when the Athabasca River joins the Peace River beyond Lake Athabasca to become the Slave River, the low flows in that river system are not as much of a concern. This is because the Peace River has the W.A.C. Bennett Dam in British Columbia that takes some high summer flows and distributes them for hydro during the winter months, creating higher-than-natural flows in the Peace and Slave rivers—by about 700 cubic metres per second. If you compare that with the 16 cubic metres per second projected for the oil sands industry, we see that the low-flow concerns are really a concern only for the Athabasca River.
These low flows have been regulated by the federal and provincial governments, with water restrictions during these low-flow periods capping the cumulative amounts of water available to the oil sands industry. This is in the Water Management Framework: Instream Flow Needs and Water Management System for the Lower Athabasca River.
This framework was released in 2007, after seven years of multi-stakeholder research, resulting in a very protective and conservative framework. It applies to segments four and five of the lower Athabasca River, and these are the segments where we find the oil sands mining operations. It limits water withdrawals by the oil sands operators during low-flow winter periods to between eight and 15 cubic metres per second, depending on the river flow and the time of the year.
This process is being refined in a multi-stakeholder process, taking advantage of additional research on the river, with a phase two water management framework anticipated for implementation at the beginning of 2011.
So what does this mean? Given the projections of oil sands mining growth to a peak of 16 cubic metres per second, and given the protection provided by the lower Athabasca River water management framework, what does this mean for withdrawals and natural flows?
On this next slide, we've taken the driest period on record at the Fort McMurray gauge, as contained in the period of 1998 to 2004. The natural flows are the blue curve on the slide. You can see the low winter flows, and you can see the high summer flows and variability of the flows on the hydrograph. The other curve—which is difficult to make out—is the amount of water that will remain in the Athabasca River if that growth case of 16 cubic metres per second comes to pass.
With the protection provided by the water management framework, we see that the difference between that rate, even for a growth case during a very dry period, and the natural flow of the Athabasca River is almost imperceptible. However, we are concerned about those low winter flow periods, and research is ongoing in that area.
There have been some suggestions that the Athabasca River is drying up in the winter. This very much depends on the timeframes that we look at. If we take a look at the high-flow periods from 1970 to 2004 at the Fort McMurray gauge, we can see there's quite a steep declining trend. It's a little difficult to see on the chart, but if you take a look at the full record of flow history on the Athabasca River at Fort McMurray, you see that from 1957 to 2007, the trend—including a forecast for the future—is much less alarming.
The town of Athabasca, which is upstream of Fort McMurray, has a longer flow history, and the river flows track very similarly. Of course, it's a smaller river upstream, because of fewer tributaries entering into the river. At the town of Athabasca, we have a full century of monitoring data, and if we take a look at that full history, we can see there have been no trends in flows recorded over the last century on the Athabasca River. There are seasonal increases and decreases due to seasonal and longer-term fluctuations in the weather patterns.
However, that having been said, if the flows in the Athabasca River were to decrease because of climate change or for other reasons, the effect would be that the water management framework would be implemented more often, and that would restrict the oil sands withdrawals more often in order to ensure protection of the river.
In addition, industry would manage the reduced water availability through the use of various mitigation tools, including the use of additional off-stream storage, thus spilling storage in the wetter periods, the summer high-flow periods, and then using that water shortfall in those winter periods. In addition to that, we can expect ongoing water efficiency improvements. As well, we've heard about some new technologies that may be promising.
I'd like to spend a couple of minutes talking about the oil sands in situ industry, which is quite different from the mining industry.
Water is also critical for most in situ oil sands production, and as the industry grows, so does the requirement for source water. However, increases in fresh-source water demand have been offset by a number of initiatives, including the transition to the use of saline water--water that's too salty for potability or agriculture--and high recycle rates of water produced with the bitumen. These rates are greater than 90% and sometimes approach 100% in some years.
I'd first like to call your attention to the black line on the chart. It indicates the bitumen production or oil production from the in situ oil sands industry. We can see that over the last 20 years there has been a sixfold increase in production.
In contrast, the blue curve, which indicates fresh water, shows fluctuation over the years. We have seen a slight increase in recent years, but the volume of fresh water has been greatly offset by the volume of saline water used, especially since 2002. There has been quite a steep increase in the use of saline water over fresh water, and you can see for the first time in 2007 that the industry now uses more saline water than fresh water for recovery.
We would expect that trend to continue into the future, depending on the availability of saline water. Depending on this mixture, by 2020 the in situ oil sands industry's forecast is to use between 25 million and 45 million cubic metres of fresh water to produce more than 1.6 million barrels of oil per day, or 90 million cubic metres per year. This represents less than 0.5% of Alberta's current water allocation to produce almost 40% of Canada's total crude oil.
Continuous improvement is also an important aspect of the industry. The chart here shows the water use efficiency of Imperial Oil's Cold Lake operation. It's in terms of units of fresh water per unit of bitumen produced. We can see that over the last 30 years there has been a dramatic reduction in the amount of fresh water required to produce each incremental barrel of oil. It is this record of continuous improvement that gives me confidence that the oil sands industries, both the in situ industry and the mining industry, will continuously improve their water use efficiency.
In closing, I'll mention that some new projects in the in situ industry, such as Devon's Jackfish project, use only saline water for steam generation. They're not using any fresh water at all.
Thank you very much.
I'd like to now introduce Ian Mackenzie, who will talk about water quality.
:
Good morning. I'm going to talk about water quality as it relates to the environmental impact assessment process in the oil sands region in Alberta. My presentation is going to focus exclusively on surface mines.
I'd like to first introduce a slide showing the bitumen outcrops along the Athabasca River. I think it can be seen that water quality has to be influenced by hydrocarbons and polycyclic aromatic hydrocarbons, which I'm sure you've heard about. Then I think it's worthwhile to recognize that based on this water quality and bitumen association, the ecosystem in the Athabasca River has likely adapted over thousands of years or been influenced over thousands of years by these deposits.
I'll frame my presentation on the environmental impact assessment with a focus on water quality by five basic elements: characterization of existing water quality; assessment of project design; confirmation of appropriate mitigation measures; cumulative assessment of water quality in receiving streams; and resolution of residual issues.
There has been extensive monitoring of water quality, sediment quality, and benthic invertebrates and fish, not to mention hydrologic monitoring in the lower Athabasca River for quite some time by numerous agencies. The federal government, through Environment Canada and the Department of Fisheries and Oceans, was involved in the northern rivers basin study from the mid-1990s to the end of that decade. The Panel on Energy Research and Development has been funding dozens of studies since the early 1990s on the lower Athabasca River. The northern rivers ecosystem initiative carried on the recommendations and studies of the NRBS, starting at the beginning of this decade and finishing up in 2003 or 2004. Alberta Environment and its predecessor has been monitoring water quality monthly upstream of Fort McMurray, and downstream of the oil sands development at Old Fort for quite some time.
Alberta Environment has also been involved in the northern rivers basin study with the federal government. You'll hear more about the regional aquatics monitoring program that was initiated in 1997. I'd also like to mention a couple of other regional bodies that have been doing a lot of work in the oil sands area. The first one is the Canadian Oil Sands Network for Research and Development, or CONRAD, which has been funding studies since the early 1990s on many aspects of oil sands, including wetlands research into potential acidification, tainting, loading studies in the river, and many others. In addition, the Wood Buffalo Environmental Association, or WBEA, has been monitoring potential stream acidification for some time.
The Cumulative Environmental Effects Management Association, or CEEMA, which you'll hear more about this afternoon, has been developing several management frameworks on potential acidification of lakes, management of streams, reach-specific water quality objectives, pit lakes, and several other things.
Industry also has to carry out monitoring associated with its approvals, which can be quite extensive. Proponents that are undertaking the EIAs also have to undertake extensive baseline work associated with that assessment.
None of the agencies and programs I've just talked about have been able to detect any effects of oil sands operations on the lower Athabasca River. I have a number of testimonials, and they are just a subset of many more that exist. For example, the PERD study, as reported in the northern rivers ecosystem initiative report in 2003, indicated there was “no evidence to indicate that local industries are contributing significantly to measured hydrocarbon levels or biotic impacts”.
Alberta Environment, in their 2008 report entitled Alberta's Oil Sands: Opportunity. Balance., reported:
Stringent testing has consistently shown there has been no increase in concentrations of contaminants as oil sands development has progressed. In fact, contaminant levels in other rivers in the area with absolutely no industrial oil sands activity have been found to be higher than those adjacent to oil sands projects. The contaminant sources in the area are natural
RAMP, in their 2007 technical report, indicated:
Based on comparisons of water quality between upstream and downstream stations over time, no effects of local human activities were apparent on water quality in the Athabasca River in 2007.
Finally but not least, Evans, an Environment Canada researcher, and others stated in a published paper in 2002:
There is little or no evidence of temporal trends of increasing PAH concentrations in sediment cores collected in Lake Athabasca and the...delta lakes, suggesting no or minimum impact from oil sands operations.
The mitigation measures that are proposed and in place in existing oil sands operations--against which EIA practitioners gauge their effectiveness--include sedimentation ponds that trap particles associated with muskeg and overburdened drainage waters in advance of mining. These waters are released to receiving streams. There are closed-circuit operations of all process-affected waters and waters that may come into contact with exposed bitumen during mining operations.
Tailings are in back-filled cells, of which I have an accompanying diagram. You can see that the tailings are deposited in such a way that associated seepage is directed to reclamation features that are specifically engineered to remediate those waters. On the right side of the diagram you'll see a receiving stream. That is protected by the placement of low-permeability materials to prevent seepage from travelling in that way. Each site-specific circumstance is very unique; this is just a conceptual diagram.
The appropriate design of tailings ponds and tailings sand structures includes perimeter ditches to collect seepage and run-off from the structure. Many of the new tailings ponds that are being proposed include interception wells around the outside of these structures to collect water and put it in the closed-circuit system.
At reclamation of these structures, the hydrostatic head or water pressure is reduced from the top by removing that water and tailings, so the amount of seepage is very small and can be handled within the reclamation landscape. Sustainable reclamation landscapes are developed specifically to remediate seepage on the landscape through engineered wetlands, and then ultimately through pit lakes that have to meet regulatory standards before releasing to receiving streams.
After EIA practitioners confirm, using conservative modelling, that the proposed mitigation measures are adequate to protect local receiving streams, integrated modelling is conducted to ensure that all environmental pathways are considered cumulatively under several different conditions of flow and several timeframes, as well as under many conceivable development scenarios. These state-of-the-art models include integrated outputs from groundwater models, air quality models, and surface water models. The water quality models are then used to ensure that the predictions are robust and in compliance with regulatory benchmarks and thresholds.
Sometimes an iterative process has to take place when it's shown that important thresholds might not otherwise be achieved. Additional mitigation and refinement of modelling assumptions have to take place. That might form the basis of the application that is submitted to the regulators and stakeholders. These submitted EIAs are then reviewed in a transparent and open process that often includes independent expert reviews.
For example, the federal government, through DFO and Environment Canada, has funded international peer reviews of some of the water quality and quantity work. Industry has also funded international peer reviews. Stakeholders also contract independent expert reviews on a routine basis for their assessments.
Given this rather lengthy and comprehensive process, the EIAs in the region continue to predict that the effects on the lower Athabasca River will be negligible and will continue to be negligible into the future.
In the final analysis, regulatory authorities along with stakeholder experts have ample time to review these EIAs and integrated applications and ask clarifying questions of proponents, who respond through formal and informal processes. This clarification process often lasts a year or longer in the oil sands area.
Issues that may not be resolved through the process are carried on to joint federal-provincial hearings for resolution and discussion. At the end of the day, if the project has been ruled to be in the interest of the public, the joint panel makes recommendations that are put into conditions, approvals, and regional programs to validate that systems are operating effectively and ensure that actions taken into the future are protective.
Thank you.
I'd now like to introduce Fred Kuzmic, who represents RAMP.
:
I'd like to thank the committee for the opportunity to talk today a little bit about the regional aquatics monitoring program, RAMP. I'm past chair and technical chair of this group.
RAMP is really a joint monitoring environmental program that assesses the health of the rivers and lakes in the oil sands region. It's a science-based program that's funded by industry and has multi-stakeholder representation from a broad range of stakeholders in the region. The program was initiated in 1997 and has been ongoing ever since.
A number of industry members are involved in the program. Some of them aren't oil sands companies. A number of government agencies representing both the provincial and the federal governments, including Fisheries and Oceans Canada, Environment Canada, and Health Canada, are part of the RAMP technical group and helped design the program and the technical aspects of it.
Under Environmental Protection and Enhancement Act approvals, operators in the oil sands region are required to conduct aquatic effects monitoring. They can do that themselves, or they can do it through participation in RAMP, which most of them choose to do.
The intent of the RAMP program is really to monitor aquatic environments in the oil sands region and compare that information with the environmental impact assessment predictions. RAMP also has the task of collecting baseline information to characterize the natural range of variability in the area. Again we collect information to compare against EIA predictions to see if they are accurate. Finally, we collect some information to fulfill the particular EPEA approval requirements that operators have.
RAMP is a program that uses both stressor- and effects-based monitoring approaches and achieves a holistic understanding of the potential impacts on the aquatic environment. We try to recognize and incorporate traditional environmental knowledge from some of our first nation stakeholders into the program. We try to communicate with the communities, the regulators, and other interested parties to share information we have. In fact, we publish a technical report each year that summarizes the activities of the monitoring program.
One of the important aspects of RAMP that we're really proud of is the continuous improvement part of it. We really try to focus on reviewing the results and looking for ways to modify the program in reflection of changing science or additional monitoring mechanisms that become available to us.
RAMP is made up of five or six key components. There are some slides that follow, so I'll detail some of the aspects of those further on. But let's start with climate and hydrology.
The climate and hydrology component of RAMP is really there to monitor the changes in water level of selected lakes and the quantity of water flowing through rivers and lakes. That's accomplished through a series of snow course surveys, hydrometric stations on the Athabasca River, and hydrometric stations along a number of the tributaries, including the Muskeg River. There are, in fact, ten hydrometric stations on tributaries north of Fort McMurray, and three hydrometric stations on tributaries south of Fort McMurray. We've taken water levels at three lakes as well.
In terms of the fish populations component, these are biological indicators of ecosystem integrity, and they're a highly valued resource in the area. There's another slide that follows on that, and I'll get into the details of that a bit more.
In terms of benthic invertebrate communities, we look at the aspects in rivers, lakes, and in the Athabasca River delta, the Peace-Athabasca delta. These are biological indicators that contribute to fish habitat, so it's important for us to look at these as well.
The final component of our RAMP program is acid-sensitive lakes. Here, water quality is reviewed as an early indicator of potential effects of acid deposition. RAMP has identified 50 of the most highly susceptible acid-sensitive lakes. We monitor those on an annual basis, looking at trace metals, general water quality, phytoplankton, and zooplankton. The indications are that we have 50 acid-sensitive lakes in the monitoring program, as well as 11 or 12 tributaries that we deal with outside the Athabasca main stem.
There are a couple of regional initiatives that are under way where people can contribute to the RAMP program, and I note a few things that they've noticed.
The first one is the river response network. This provides emergency response to public reports of non-spill events such as fish kills, the presence of foam, or scum floating down the river. This is an effort we have in conjunction with Alberta's environment protection ministry. They have a 1-800 number where they report that information.
In terms of the fish tagging program, this is an opportunity where we encourage the public to report tagged fish. Part of the fish populations program is the capture, tagging, and release of fish. When these fish are caught by fishers downstream or somewhere else in the river, they can report that back with the numbers that are on the tags.
In fact, just in terms of some information, walleye tend to be very far-travelled. In some cases we've had tag recoveries about 715 kilometres from the initial tag sites—in Lesser Slave Lake in the middle of the province at one of the upstream edges of the Athabasca basin—and as far downstream as 403 kilometres along the Slave River. So these fish tend to be far-ranging.
The fish health program that we have promotes reporting of abnormal fish. So if a fisher catches something that looks strange or odd—if there are fish with lesions, growths, or physical abnormalities, such as curved spines or blindness or missing fins—they're encouraged to call the number that we have published and report the information to us so that we can take the fish and send it out for further analysis at the veterinary school.
If you take a look at the map, the RAMP study area is pretty big. It covers the entire regional municipality of Wood Buffalo. There are upstream monitoring sites from the oil sands operation, and downstream of Fort McMurray; and then there are some far downstream sites on the Athabasca River delta that look at the potential effects of development in the region.
The regional study area covers off the RMWB, as I said, but the focus study area looks at particular areas and watersheds where oil sands development is occurring, or is planned to occur in the future. So it's really keyed to those particular areas.
Take a quick look at some of the water quality information. As I mentioned before, water quality and sediment quality are two important components of our program. We look at all the regional tributaries of the rivers, and there are some lakes where the information is reviewed, and then out on the Athabasca and Peace River deltas as well.
The water and sediment quality reflect habitat quality, as well as potential exposure of fish and invertebrates. We have 45 sites that are sampled at a minimum annually, but there are some sites that are sampled monthly. There are 28 different sediment sites that we collect sediment samples from, and those are tied into the benthic invertebrate program as well.
We do toxicity testing. We analyze for polycyclic aromatic hydrocarbons. There are some potential fish-tainting compounds for which we analyze those particular materials as well, and there are some thermographs that we have to monitor for changes in water temperature.
The next few slides really just run through a couple of snapshots for the 10-year monitoring period between 1997 and 2007 on a few key components. The thing you'll notice is that each of them is below current guidelines—either CCME guidelines or other particular guidelines that apply—and there hasn't been a lot of change between the upstream and the downstream, or no change in most cases, between monitoring upstream and downstream of oil sands operations.
Maybe we could just flip through these slides. The first slide is of arsenic concentrations, the second of sulphate concentrations, and the next is of dissolved organic carbon concentrations. You can see that the purple represents the downstream sites and the green triangles represent the upstream sites.
The last slide on water quality that we have here is on PAH concentration, the polycyclic aromatic hydrocarbons. You can see there is a bit of fluctuation on some of those. The levels at upstream sites can be higher, depending on erosion that's occurring along the river, or seepage from some of the sites that Ian mentioned earlier. But the downstream sites tend to be fairly consistent over the period of record. So this is really showing no change across the region.
The benthic invertebrate samples are really biological indicators that reflect fish habitat and the quality of the sediment. There are 29 different locations on 23 river locations, three on the Athabasca River delta and three at the regional lakes. We measure both erosional and depositional habitat. There are 10 replicates collected at each of those sites, so there is some strong statistical power to the analysis that we do. And we collect the required physical measurements as well. None of the sediment samples are showing any changes in sediment quality. The benthic invertebrate community structure is similar and shows no change from previous data.
So one of the primary conclusions from the 2007 RAMP technical report—you can see the quote there—is that there have been no major effects on benthic invertebrate and sediment quality, as supported by the watershed and lake level analysis.
Talking about fish populations, the RAMP program each year does spring and fall inventories on the Athabasca and Clearwater rivers. In 2007 we collected just over 3,500 fish, and 2,500 of those were caught in the Athabasca River. A number of those fish will be tagged and released, but all of the fish are measured, weighed, and sexed so that we can come up with length and weight distributions and the age structure. There are 19 different species that we record in our inventories. These include walleye, northern pike, goldeye, and long nose sucker, to name a few. And we've seen no ecologically relevant level of change in any of the fish populations, which is really indicative of just natural variations.
We see that “sentinel (fish) species monitored in potentially influenced sites have not exhibited consistent differences in comparison to reference sites”.
This is a non-lethal monitoring program we've employed over the last few years to look at upstream-downstream young of the year, to analyze any changes that may be occurring to those populations and the growth expectations related to any development.
There are some other aspects of the fish population study. We do fish fences, as well as the electrofishing and the monitoring that goes on in conjunction with the sentinel species work.
We're the only agency right now that is collecting tissue samples and analyzing for mercury. That information is passed on to Alberta Health and Wellness, Environment Canada, and Health Canada for continuation of the fish consumption advisories.
With that, I would like to turn the floor over to Greg.
In the interest of time, I'll keep my comments relatively brief.
I want to talk about two main things. You've heard the regulatory story and what has been going on today, but I want to talk a little bit about the technology advances that are going on. We have a second panel that will come and talk about specific examples, but I thought it would be important for you to understand the research and development and the pilot projects that are going on in both the mining areas and what we call the in situ or the underground areas, to try to reduce the amount of water use, increase the amount of recycle, or in many cases, as you heard, shift from fresh water to saline water and other sources, even using solvents instead of that.
In the mining area, the chart outlines a couple of things that are going on. I know you had presenters from the University of Alberta yesterday. There is a centre there for oil sands innovation that is looking very intensely at water issues associated with that from a research and development perspective. In addition to that, as you've heard in regard to a number of other research activities that are going on, there's a very strong push right now to increase the recycle rates and reduce the amount of tailings. Some of those examples include such things as consolidated tailings—in other words, to get the water to separate out from the fine tailings much more quickly than it has in the past, in order to move it into a reclamation phase more quickly.
You'll hear in the next panel about CO2 injection, where they will put CO2 into the tailings to get it to thicken up, and about looking at things such as paste and dry tailings. In fact, there's an oil sands research tailing facility at the university that is looking at pushing the advancement of technology.
So while technology has already been demonstrated, as Stuart talked about, in projects that are in place to reduce the amount of water use, that technology thrust continues into the future to try to look at what would be possible and practical in the future.
The one that probably has the most work going on right now is the dry tailings technology. I think you probably heard about that, but really that is to get to what they call a trafficable--you can walk on it--type of reclamation much more quickly. Shell, Chevron, and Marathon have the $100-million pilot project at Muskeg River, the plant that you flew over on Monday.
As well, NRCan is directly involved, and you can see some of the pictures from the NRCan studies with Syncrude and Suncor that really have the pilots scaled towards these dry tailings. It has not been perfected yet. It's not completely there, but it is getting much, much closer, and the research continues to go on.
Today, that's about 20% of the resource in the mining area. The other 80% is in the in situ area. That's the future resource. Production today is about half and half: about half the oil comes from mining projects, and about half of it comes from in situ.
In the in situ projects, there are some very exciting technologies going forward that will reduce the total environmental impact, including in terms of water. The one that we've shown on the top is the in situ combustion. We have them presenting on the second panel, and they will talk about how they will use underground heat in order to avoid the use of water and still recover the bitumen coming forward. There's no steam that is required for that process at all, and it is up and running, as you'll hear from Petrobank in a few moments.
Other areas on the in situ side of things that are very promising advances, in addition to the shift to saline water, include using solvents, reducing the amount of water or steam that is required, and using things such as propane to be able to get that thick bitumen thin enough to be able to come up the well to the surface. This has really shown some good promise and is done in some pilot projects at this point in time. They're even looking at potentially using full solvent recovery, which would replace water completely, and being able to recover the bitumen that way as it moves forward. That has been done at the lab scale but hasn't yet moved out into the field.
So there are some technological advances that I think are really promising, that continue to push the technologies, as they have in the past. Technology has been a real key to unlocking this resource, but also is a key to the environmental protection.
I'll just quickly summarize. As you have already heard, the balance for us is really critical. We recognize that the water resources are very valuable and need to be managed appropriately, need to be balanced with economics and the environmental and social aspects of development.
To put it in context, in 2008, for example, the oil sands industry used a little more than a third of the amount of water used by the city of Toronto, and that produced about half the oil being produced in Canada. Even if we project into the future, as Don talked about, if we look at maybe 3.3 million barrels a day, and with the decline in conventional oil, about 80% of our oil in Canada would come from the oil sands. At that point in time, we also know that's going to be capped off at 2.5 percentage points of the annual flow of the Athabasca River, in addition to these new technologies on the in situ side of things. So we think we can achieve the balance and we know we need to continue to improve.
We talked about the regulation. The water use and the related impact such as quality are regulated by both federal and provincial authorities, and there's extensive monitoring in place that comes from the governments, as well as from government multi-stakeholder and industry associations that look at that quality on a regular basis and make that information and those reports available to the public.
I already mentioned the split between mineable and in situ, but I also want to come back and say that there has already been significant improvement in water use. We really are striving. There are economic as well as environmental reasons to reduce the amount of water and to increase the amount of water recycled. We can use the water over and over again after there is an initial draw-in. In many projects we're up to greater than 85%, and some of them are up to 95% recycled water. They draw on the water, but then they use it continuously throughout the life of the project.
Last, I want to emphasize the point on technology. Technology has already shown significant gains in helping us reduce the amount of water, finding technologies that don't need water, and pushing those technologies forward. It will still be a critical part of achieving environmental performance into the future.
I'll keep my comments short and turn the time back to you, Mr. Chairman.
Thank you.
:
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.
:
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.
:
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.
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.
[Translation]
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.
[English]
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.
[Translation]
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.
[English]
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.
[Translation]
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.
:
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.
:
Thank you for providing us the opportunity to present here. We're very happy that the committee has come to Alberta.
My name is Simon Dyer. I'm the oil sands program director at the Pembina Institute, where I manage Pembina's research on oil sands development.
The Pembina Institute is a national sustainable energy think tank that works on sustainable energy solutions. We were founded in Drayton Valley, Alberta, in 1985.
We have researched the environmental impacts of oil sands development for over a decade and we are committed to responsible oil sands development. Unfortunately, Canada’s current approach to oil sands development is a case study in unsustainable development.
The manner in which the oil sands have developed includes many areas of federal jurisdiction beyond impacts on water. Unfortunately, the federal government has been very weakly involved in oil sands environmental management to date, despite these significant areas of jurisdiction.
I have a presentation that I've circulated in hard copy. I hope you will follow along with that.
Given the limited time available, I'll focus my comments on three main areas--the lack of protection of the flows of the Athabasca River, the unsustainable management of tailings, and the lack of adequacy and transparency in monitoring.
The federal-provincial management framework for the Athabasca River gives priority to oil sands production over protection of water and fisheries. Under the water management framework for the Athabasca River, there is no legal requirement for water withdrawals to be halted in order to protect fish habitat. The water management framework has a traffic-light system, identifying green, yellow, and red zones. During the red zone, fish and fish habitat are being damaged. Unfortunately, in this instance, red does not mean stop, and water withdrawals are allowed to continue, even when fish habitat damage is occurring.
Slide five looks at the current and future risks posed to water by unsustainable tailings management practices. It's estimated that there is a total of 720 million cubic metres of impounded liquid tailings on the landscape north of Fort McMurray. This amounts to 288,000 Olympic swimming pools of toxic waste. Tailings lakes now cover 130 square kilometres of land. That's an area the size of the city of Vancouver. On average, one and a half barrels of liquid tailings accumulate for every barrel of bitumen that is produced.
In over 40 years of oil sands development, no areas containing tailings have ever been certified as reclaimed, and industry has never demonstrated that they are able to deal with the toxic liquid waste in tailings lakes.
When you hear evidence from industry saying the first tailings ponds will be reclaimed in the next few years, this is misleading. The mature, fine liquid tailings will simply be piped to another location while those tailings lakes are filled in. Tailings lakes are toxic and contain hydrocarbons and naphthenic acids at concentrations of up to 100 times those found in bitumen.
Another risk is the risk of the catastrophic discharge, of course, which would be unthinkable.
In addition to the risks associated with current tailings production and the current risks in terms of seepage, which I'll talk about shortly, a bigger risk, I think, is the long-term fate of these tailings. Most Canadians would likely be astonished to learn that the accepted way to deal with this liquid waste in the long term is with an unproven concept called the “end pit lake”.
Other industries have end pit lakes. It's a place where you put water in a gravel pit at the end of the gravel pit's mine life, for instance. The oil sands are unique in that their tailings lakes or their end pit lakes will include toxic liquid waste at the bottom. The approved plan is simply to cap the liquid tailings waste with fresh water and hope that through a process called meromixis, in perpetuity, the upper water layers do not mix with the lower layers.
In slide eight, I show a cartoon from CEMA, the Cumulative Environmental Management Association, that shows exactly how these toxic liquid waste dumps are going to be a permanent feature on the landscape.
It's not possible to overemphasize what a risky and unproven concept this is. Concerns about the fact that this concept of an end pit lake has never been demonstrated are continually raised by federal and provincial regulators and by CEMA, yet all oil sands mines have been approved so far with this method. There are 25 end pit lakes approved and proposed so far on the landscape. There's a quote in my presentation that shows how, really, this is a complete experiment. We've never demonstrated that this is a sustainable solution.
I now want to talk about tailings seepage. Tailings lakes are leaking. I know you've heard mixed opinions on this during your stay. It's not surprising that there are mixed opinions, because there is a real absence of publicly available data to get to the root of this problem.
Last year, the Pembina Institute was commissioned to conduct a review of potential seepage from tailings ponds. We contacted the Government of Alberta on at least three occasions, asking for information on seepage data from groundwater wells. No data was provided on any occasion. It is unclear whether cumulative summaries of the data exist, whether the governments of Alberta or Canada have the capacity to analyze that data, or whether the Government of Canada has seen that data.
Despite some of the testimony you may have heard, assessments project that all tailings lakes leak, even after mitigation measures are accounted for. So even after the pumping you've heard about to move that material back to tailings lakes, there is still residual leaking into the environment--into the groundwater and the Athabasca River and its tributaries.
We did a very conservative assessment of environmental impact assessment data and found that tailings lakes could be currently leaking into the ground water at a rate of 11 million litres per day. This rate of leakage could more than double if current proposed projects proceed.
Occasionally, actual validated information on seepage is available. For instance, if you look at some recent approvals for Suncor, it was reported that their pond 1 was leaking into the Athabasca River at a rate of 1,600 cubic metres per day.
Finally, I want to comment on the availability and adequacy of publicly accessible data on oil sands environmental performance.
One of the unfortunate defining features of oil sands development is the lack of transparency and the absence of publicly available data for many elements of environmental concern, such as tailings seepage, tailings reclamation performance, and access to RAMP data. A clear and cumulative picture of the potential scale of tailings lake leakage has never been presented by the Alberta or federal government. It's been up to environmental organizations to try to project what those impacts may be.
There are many stakeholder concerns about inadequate monitoring of the Athabasca River. The regional aquatic monitoring program, RAMP, has been criticized as lacking provincial and federal government leadership. Federal reviewers of RAMP have raised significant concerns about the program itself, and we are not aware that these shortcomings have been addressed.
I'll also make it clear that the Pembina Institute has not been a member or participant in RAMP over the past six years. We simply have concerns about the credibility of the program and lack capacity to participate in all these different processes.
In conclusion, we urge the federal government to play a much more active role in oils sands environmental management. I would like to draw your attention to three specific recommendations.
First, we recommend that the federal government ensure no new approvals for oil sands mines until a scientifically based ecosystem base flow for the Athabasca River is established, beyond which withdrawals by all oil sands operations during the red zone or low-flow periods would be prohibited. The tragedy is that using off-stream water storage is an economically viable approach for the industry, but there's no regulatory requirement to store water and halt withdrawals, so we continue to see withdrawals during these low-flow periods.
Second, the federal government should ensure that no more oil sands mine approvals should be granted that include mature fine tailings or that propose unproven end pit lakes as a reclamation strategy.You've heard a lot of talk about the technological silver bullets that are going to improve the oil sands industry, but technology in the absence of regulation isn't going to drive the sort of change we need to see. Industry has been researching tailings ponds for 40 years, and it hasn't demonstrated they're able to deal with the solution. We need the regulatory levers that prohibit this unsustainable practice.
Finally, independent and transparent monitoring that has a strong, peer-reviewed, scientific basis is needed. Federal leadership is required to ensure that the data is publicly available and greatly enhanced. It should include comprehensive water quality, tailings reclamation, and tailings seepage information.
Thank you very much.
:
Thanks for the opportunity to speak to you today on what I see as one of the most important freshwater issues in Canada today.
My name is Tony Maas. I'm senior freshwater policy adviser with WWF Canada.
As some of you may know, and as others may not, WWF Canada prides itself on being a science-based and a solutions-based organization. What that means is that we tend to focus our efforts on working across sectors--public, private, not-for-profit--to look for and implement solutions to today's increasingly complex environmental problems, as long as we understand, as well as possible, the underlying science. When we don't understand that science, or when it is incomplete or in question, we advocate precaution.
With that as an early background, not unlike my colleague from the Pembina Institute, I'm here recommending that no further approvals for oil sands projects that require water withdrawals be granted in the near term. I make that recommendation because we believe decisions are being made in the absence of best possible science and with little or no precaution.
I should also note here that WWF is an active member of the phase two management framework committee, the P2FC. This is the group of industry, first nations and Métis, and other environmental organizations, as well as federal and provincial government representatives, that is working to develop a recommendation for what we hope will be an improved water management plan for the lower Athabasca River. As part of that, we have agreed with our colleagues on that committee not to discuss publicly the internal workings of the committee, as it's ongoing.
I'm going to frame my discussion around the concept of environmental flow, or what in Alberta is often referred to as instream flows.
Aquatic ecologists widely recognize that a river's natural flow regime--the peaks and troughs, the high and low flows--is critical to sustaining the integrity and productivity of freshwater ecosystems. The Athabasca River is unique when it comes to environmental flows. It is unimpeded by dams, so flows are largely natural. It is in fact the third-largest free-flowing river in North America.
Because the Athabasca is not impeded by dams and other infrastructure, there is significant interannual and intra-annual variability. It is this variability that sustains not only the integrity of the river but also the downstream Peace-Athabasca delta. That delta, as you might know, is 80% protected by Wood Buffalo National Park, which is a UNESCO world heritage site.
Also worth pointing out in connection with this interannual and intra-annual variability is that winter low-flows are the most critical period of time for the health, productivity, and survivorship of species in the Athabasca River, simply because flows are lowest at that point.
When we talk about environmental flows, it's important to recognize that there are sustainable limits to the degree to which we can disrupt flow regimes. When we think about this in the context of oil sands development, it appears very much that we put the cart before the horse.
Alberta Environment has licensed oil sands operators to extract significant volumes of water from the Athabasca River before setting sustainable limits on those withdrawals and before appropriate protections were put in place. This has been acknowledged, in fact, through the phase one management framework approach; however, we believe the phase one management framework for the lower Athabasca, the existing management framework that is in place, is inadequate, for at least three reasons.
First of all, as has been mentioned, there is no ecosystem base flow. An ecosystem base flow is essentially a threshold or limit below which, in order to protect the ecosystem, no further withdrawals from the river should be allowed. However, under the phase one approach, industry is allowed to take at least 5.2% of the median flow at any time, regardless of the severity of low flow.
It's important to recognize that some of the statistics that were put out this morning around the percentage of annual average flow that oil sands operators take from the river can be very misleading. The important timeframe to be considering is the period of these very low flows. At these times, the proportion of flow being taken by oil sands operators is much more than the annual average numbers would lead you to believe.
Second, there are no provisions for peak flows, those high flows that are very important to replenishing the Peace-Athabasca delta. The phase two framework simply assumes, without significant scientific support, that withdrawals will not affect ecosystem health, and it will therefore allow operators to withdraw the maximum amount of water they can during that period of time.
Finally, and I think incredibly importantly--it's come up a number of times--the phase one framework failed to acknowledge the impacts of climate change on future flows in the Athabasca River. Science tells us that flow is in fact declining in the Athabasca River, and that the decline is largely due to human-induced climate forces.
Over the past couple of years, WWF has commissioned reports by Dr. Jim Bruce, who some of you may know. He's the chair of the groundwater report that has been mentioned a number of times. He's also a member of the Intergovernmental Panel on Climate Change and a world-renowned, Canadian-renowned, climate scientist.
In a report commissioned by WWF, Dr. Bruce predicted that by 2050 the mean annual flow of the Athabasca could decline by 25%, and low flows could decline by 10%. We recently asked Dr. Bruce to update his report. What came out of that was a warning that his early predictions might be wrong for a couple of reasons, and that flows might decline quicker.
Those reasons include the fact that greenhouse gas emissions are increasing more rapidly than the IPCC assessments suggest, and headwater glaciers that provide some of the base flow to rivers like the Athabasca have passed the tipping point. They were providing more flow to rivers because of melting, and are now providing less base flow.
Finally, when we think about environmental flow we can't forget the quality dimension. It is important to recognize that when we're looking at the flow of a river, it carries pollution from upstream activities to downstream communities and ecosystems. I think an important way of looking at this is as an issue of watershed equity. When we are putting downstream communities at risk, we are putting ourselves increasingly in a position of conflict.
At the heart of this issue is the tailings ponds that have been discussed at length today, the seepage from those tailings ponds and its impact on the health of downstream communities such as Fort Chipewyan. But when you think about the potential--regardless of how low it might be--for a catastrophic breach of a tailings pond, the watershed equity issue stretches well downstream into the Mackenzie River basin, including the Northwest Territories.
Here again there's significant uncertainty related to the human and ecosystem impacts associated with tailings seepage, but there's also significant uncertainty related to how pollutants would disperse in the event of a catastrophic tailings breach.
To conclude, I think it's safe to say that for too long oil sands development has progressed without the appropriate oversight and leadership of the federal government. There are clear indications that the federal government has an incredibly important role to play and responsibilities in the realms of fish and fish habitat protection, transboundary water issues, and protection of aboriginal rights. What has been called a complex and confusing allocation of water management powers between federal and provincial governments is often used as an excuse for inaction.
We have a couple of specific recommendations for the federal government to demonstrate and take leadership on freshwater issues related to oil sands. Federal leaders, including the Minister of Fisheries and Oceans, should be encouraged to support the recommendations that come out of the phase two water management framework committee, and ensure that the framework has full political support so it moves toward an implementable water management framework and is resourced so that it can be implemented and enforced.
As you may be aware, under the original phase one management framework, a DFO biologist proposed a more stringent approach that was much more protective of the ecosystem. It included an ecosystem-based flow; however, it is unclear to us why that approach did not end up as part of the phase one management framework.
Finally, there is an opportunity here for the federal government to show leadership in an area where there is potential for growing conflict around transboundary water issues within this country. Alberta and the Northwest Territories are in the midst of negotiating a bilateral agreement under the Mackenzie River basin transboundary agreement. The federal government is a party to that agreement, and we recommend that the federal government participate in those negotiations to ensure that what emerges out of that is a robust water management plan that ensures watershed equity and reduces conflict.
Thank you.
:
Thank you, Mr. Chair and committee members, for the opportunity to present to you today.
My name is Barry Robinson. I am the staff lawyer at Ecojustice Canada, formerly the Sierra Legal Defence Fund.
Karin Buss was scheduled to present to you today, but unfortunately she fell ill this morning. She sends her apologies.
The focus of our written presentation and my comments today is the role that the federal government should and must play in the management of our water resources in the Athabasca oil sands region. It is our submission that the federal government has been somewhat missing in action in an area where it has clear responsibilities.
In our written brief, we have provided evidence that the federal government has not been fulfilling its responsibilities to protect water resources in the oil sands regions. Today I would like to focus your attention on the fact that the federal government actually has significant powers and responsibilities that it could and should use, and I urge the committee to recommend that those powers be used.
In the Constitution Act, 1867, the federal government has clear responsibility and defined powers in certain areas, such as fisheries. In other areas, the federal heads of power overlap with the provincial powers, and thus some coordination is required with Alberta. This does not mean, however, in legal terms, abandonment of these federal powers or acquiescence to the province's regulatory regime. Practically, what it requires is leadership, advocacy, and diligent work on the part of the federal authorities.
We must keep in mind that where there is a clear conflict between federal and provincial powers, the federal powers are paramount. Therefore, it is our recommendation that the federal government should begin exercising those powers that are clearly within its jurisdiction. I'd like to run quickly over some of those areas.
First, under the natural resources transfer agreement of 1930, under which Canada transferred ownership of natural resources to Alberta, the federal government reserved to itself the right to determine and secure sufficient flows within the rivers and streams that feed into Wood Buffalo National Park, to protect its “scenic beauties”, to quote the agreement.
In modern terms, I would submit that protection of the ecosystem would fall within that broad category of protecting scenic beauties. This gives the federal government an overriding and preeminent power to determine what flows must flow into Wood Buffalo National Park.
As Tony has mentioned, the Department of Fisheries and Oceans determined in 2006 what the inflow stream needs are in the Athabasca River, so what remains to be done is for the federal government to give Alberta formal notice of what flows it would require into Wood Buffalo National Park.
Second, Canada clearly has primary responsibilities to protect fish habitat under the Fisheries Act, and low flow levels, as has been pointed out by my colleagues, can destroy fish habitat.
To date, DFO has issued HADD permits—that is, harmful alteration, disruption or destruction of fish habitat permits—only for, as far as I'm aware, the actual process of digging out streams and water courses in order to mine underneath them, to reroute streams. I am not aware of DFO issuing any permits that deal with the impacts of lower flows in the Athabasca that result from diversions of water for these industrial schemes.
In fact, I'm only aware of one permit, which is the Albian Sands permit, for their Muskeg project, that did set a restriction. This was the permit for the actual physical structures to withdraw water from the Athabasca. That did set a minimum water flow below which no water was to be withdrawn.
I would suggest that the federal government, and DFO, in its power, should be doing that on all the HADD permits they issue and on other permits they issue with respect to oil sands.
Third, Environment Canada has administrative responsibility for those provisions in the Fisheries Act that deal with depositing deleterious substances into waters frequented by fish. The courts have been clear that this includes prohibiting the seepage of deleterious materials into water that does not contain fish but which eventually discharge into water containing fish. So the discharge does not have to be directly into fish-bearing streams to be prohibited.
I am fascinated by the discussions that I heard this morning and things I've read that tailings ponds are not seeping. We did have evidence this morning that Suncor's pond 1 did leak, for a number of years, and I understand it continues to leak into the Athabasca.
The Syncrude groundwater report for 2007 indicates water seeping from their Muskeg River tailings pond into Beaver Creek. This is not theoretical, but is measured in their groundwater report, which shows that the water is seeping into Beaver Creek. It's beyond their containment system. So it's not something theoretical in an environmental impact assessment, but is actual seepage happening beyond the containment systems.
I also understand that you may have heard from Dr. Schindler yesterday that there are deleterious substances entering surface waters through air emissions. Therefore, we would ask that Environment Canada step up and enforce the deleterious materials provisions of the Fisheries Act.
Fourth, the Canadian Environmental Assessment Act requires the federal assessment of proposed oil sands projects, which I'm sure you've heard of a number of times. This not only gives the federal government the power to assess these projects before they begin, but there are also monitoring provisions in there, on which they could require follow-up after these projects are approved.
This is the area where we see some weakness, in that commitments are made during the joint review panel hearings, and then, at times, the commitments made there are not followed through on by the companies. So the basis on which the approval is granted, that certain mitigation steps will be effective, turns out to be.... Either the steps are not implemented or they're not effective, yet no one is following up on these steps.
There are other pieces of legislation and powers that are set out in our written submission, such as the peace, order, and good government provisions, which give the federal government residual jurisdiction over environmental matters of national concern, including transboundary waters.
Finally, we wish to highlight that Canada does have a water policy. It was made in 1987, and has laudable goals and strategies to protect Canada's water resources and to promote efficient water management and use. The strategies that are set out in that water policy include Canada's fiscal and regulatory powers to penalize polluters and to encourage water efficiency. The 1987 water policy also identified water pricing as a key to conservation. This policy has not been implemented, but it is a tool that could be used.
In conclusion, we would recommend that the federal government use its available powers, including spending and other fiscal powers, to improve environmental performance in the oil sands. We are asking the federal government to step up and address the water issues in the oil sands area.
I thank you for your attention.
My name is Ken Chapman. I'm standing in for Mary Granskou, who is in Vancouver today with the Canadian Boreal Leadership Council. I'm from Cambridge Strategies in Edmonton, and I'm pleased to present to you on behalf of the Canadian Boreal Initiative.
As we understand, the committee has particular interest in water quality and water quantity.
Let me tell you a little bit about the CBI. It's a national organization guided by the boreal forest conservation framework. It's a vision to support the protection of at least half of Canada's boreal forests with world-class sustainable development in the remainder of the landscape and in a manner that respects aboriginal rights. This vision is supported by leading resource companies, first nations, and conservation groups, many of them located right here in Alberta.
We get behind real solutions. Our forestry company partners actually have over 50 million acres under Forest Stewardship Council certification, and they actually lead the world in this. Our oil and gas company partners are committed to demonstrating environmental, social, and technological performance improvements. Our first nation partners are shaping land use plans and balancing protection with sustainable resource development. And we work with environmental groups to raise standards for environmental performance. We have memoranda of understanding with governments, and we cover the whole range and spectrum of the boreal forest in our partnerships.
We believe that conservation-based planning and the establishment of large, interconnected protected areas is required to ensure that development, where it occurs, will not impair ecological and cultural values. We believe that planning for sustainability of the boreal forest is the key to economic prosperity, cultural vitality, and ecological integrity.
However, we'd like to note at the outset that these approaches also require immediate action to meet the challenges presented by climate change. We recognize that without a robust global and national response to reducing greenhouse gas emissions, including substantial performance improvements in the energy sector, all bets are off. Although we will focus in this presentation on the management of terrestrial and aquatic impacts, it is in that context and with that caveat I make these comments.
Today three countries on earth are home to the world's remaining large tracts of intact forest: Brazil, Russia, and Canada. Of those, Canada's boreal forest houses one-quarter of the world's remaining original forest, and is one of the largest intact ecosystems on the planet. Protecting this global resource is a responsibility Canada has to the world. There are 1.4 billion acres spanning 58% of our gross land mass, stretching from Newfoundland to the Yukon.
Scientists are telling us that large-scale protected areas to maintain wildlife and other ecological values are important to protect this landscape. There are some areas of the boreal forest, such as in Alberta, where the need for such protection is absolutely critical. For example, woodland caribou are very sensitive to disturbance, and the boreal population is declining in this province. Unless critical habitat is protected, this already threatened species may be extirpated over its former range.
Now, regarding the oil sands' impact on the broader boreal region, in Alberta, the boreal forest covers 60% of our land mass and most of the province's forested lands. The boreal forest is an economic engine for Alberta and indeed for the country as a whole, but development in this region is having specific impacts and is presenting tremendous challenges to the climate, boreal ecosystems, local communities, and wildlife populations.
Many of these pressures result from the unprecedented pace and scale of development in Alberta's oil sands. The substantial expansion of oil sands development, combined with industrial forestry and conventional oil and gas development, is straining a range of ecological services in northern Alberta.
After 41 years of oil sands mining in Alberta, the pace of reclamation to date has not matched the rate of disturbance. The level of impact on water quality and quantity is of great concern as a result.
What is urgently needed is a solution to set new and significant land and wetland conservation commitments within an overall regulatory system that gives first priority to proactive planning to protect air, water, and other ecosystem values in the broader region around the oil sands. The second priority is to ensure the health and sustainability of local communities, and particularly aboriginal communities. And the third priority is reducing the footprint and mitigating the impacts of development in a way that can be demonstrated as compatible with the first two priorities.
We have four recommendations for you. First, we recommend that the committee support and advance a cross-jurisdictional water strategy involving all governments in the Mackenzie River basin, with demonstrated leadership by the federal government.
The Mackenzie River is Canada's longest river, and its 1.8 million square kilometres watershed drains one-fifth of the country. It is truly the heart of much of Canada's north. The oil sands are located in the Peace and Athabasca watersheds, which are critical headwaters for the broader Mackenzie basin. Our recommendations focus on remedies within this larger watershed context as the impacts of oil sands development are and will be felt through this entire region, particularly in the many aboriginal communities downstream.
There is a need for effective integrated water resources management that has given rise in the past to the Mackenzie River Basin Board and the Mackenzie River Basin Transboundary Waters Master Agreement that guides that operation. Members of the MRBB include the NWT, Yukon, British Columbia, Alberta, and Saskatchewan. In 2008 the governments of the NWT and Alberta signed a memorandum of understanding on economic development that identified water and wildlife management as two priorities.
The Government of the Northwest Territories has been engaging with first nations and the broader community to develop transboundary water strategies for the Mackenzie basin. Environment Canada has been supporting this financially.
The federal government has to become a leader in this process. As you know, Canada has specific constitutional responsibilities for fisheries, navigable waters, migratory birds, and aboriginal communities, but it is also the senior government with responsibilities for interjurisdictional environmental impact. Canada must be at this table and must be prepared to ensure that our national interests in ensuring clean water, environmental quality, and healthy, sustainable aboriginal communities are advanced through this process.
Our second recommendation is that the committee support implementation of conservation offsets through providing federal resources, particularly to advance first nations-led offsets proposals.
Status quo land management and reclamation approaches in the oil sands have demonstrably failed to keep pace with public expectations, while environmental liabilities are accumulating rapidly. There is a pressing need to put new tools and approaches into practice to address decades of delay in initiating reclamation while proactively meeting the challenges of new development.
Since early 2008, CBI has been working with first nations, industry, and other interested parties to advance conservation offset as a regulatory tool to address the impacts of industrial development in the oil sands region. Through a report and subsequent workshops, it was concluded that conservation offsets should be considered to address the gap between Alberta's growing development footprint and unrealized reclamation and conservation needs in the boreal forest. Conservation offsets are compensatory actions and can be used to offset industrial footprints by securing areas of equal or greater biological value.
As part of a complementary strategy that will require significant new conservation and protected areas; world-leading mitigation and monitoring practices to protect land, air and water; enacting and enforcing higher standards for reclamation and limits on the extent of development footprints; and dealing equitably with impacted communities, conservation offsets are one tool that can be effectively used to limit industrial footprints in order to protect biodiversity within Alberta's boreal forest. It's in this context that conservation offsets can be cost-effective and operationally efficient methods to secure important conservation outcomes, help companies strengthen their social licence to operate, and help manage reputational risk.
In fact, in Alberta, the land use framework, the Alberta Land Stewardship Act, and oil sands plans identify conservation offsets as a land management tool that would contribute to achieving desired conservation outcomes within regional planning processes.
Through financing support, the federal government has a role to play in advancing conservation program offsets. As a good parallel for this, look at British Columbia's Great Bear Rainforest agreement, in which Ottawa matched B.C.'s $30 million contribution towards a $120 million fund to implement a plan for conservation and environmentally sensitive development.
Our third recommendation is that the committee support the advancement of protected areas in the region around the oil sands and the broader Mackenzie River basin.
Due to the size and intensity of oil sands extraction, the success of actions to mitigate the impact of development will have to be a large influence on the integrity of the Mackenzie River basin itself. The ability of Canada to fulfill this international agreement and the perception of Canada internationally are at stake here.
A key component of necessary conservation offset measures is protected areas. Protected areas are needed to sustain regional ecological processes, to protect representative examples of native ecological communities, and to maintain native biodiversity. If properly selected, protected areas can act as benchmarks for sustainable management strategies for the region while maintaining ecological integrity. They can also provide an opportunity for diversification of local and regional economies, where many of the benefits have the potential to stay within those local communities.
:
Thank you, Mr. Chair. I'd like to thank you and all the committee members for inviting CEMA to appear before this committee.
In the time allotted I'll attempt to convey to the committee all the effort and good results CEMA has contributed to developers, regulators of the oil sands, and the citizens of Alberta and Canada.
CEMA is a non-profit, multi-stakeholder association based in Fort McMurray. It has an annual budget of around $8.5 million that is focused on research and studies looking at the cumulative environmental effects of oil sands development. We accomplish this through five working groups. The working groups look at air, land, and water, and also involve people issues. We have a traditional environmental knowledge advisory committee and an aboriginal round table. These working groups are composed of technical experts from our members, as well as individuals from non-member organizations with expertise, to help us tackle some of these big issues. It is a daunting task, and we rely on these volunteers to help us accomplish it.
As this can be a very intensive commitment of time, it limits the involvement of some of the CEMA members and leads to certain frustrations. CEMA has 46 members, which we call the CEMA board. This includes representatives from industry; different levels of government--municipal, federal, and provincial; first nations and aboriginal groups; and ENGOs. The federal agencies that are represented at the CEMA board are Health Canada, Environment Canada, Department of Fisheries and Oceans, Natural Resources Canada, and the Canadian Environmental Assessment Agency.
CEMA's work is guided by the regional sustainable development strategy that was developed for the Athabasca oil sands area by Alberta Environment. This was developed to provide a framework for managing cumulative effects and ensure sustainable development in the oil sands area. At that time, 72 environmental issues were identified and prioritized. CEMA was given a number of these issues, and at present CEMA is dealing with 27 of these 72 issues.
Since its inception CEMA has forwarded eight major frameworks to both federal and provincial regulators. We have forwarded a revegetation manual and a wetlands manual. In developing these documents, CEMA has produced over 200 reports and amassed a number of databases related to relevant subject matter. The majority of this information is available on our website, and we encourage people to go there and use it.
Over the last 18 months CEMA has had a number of challenges with the withdrawal of members from first nations and ENGOs. This may be viewed as entirely negative, but in fact it has thrown the ball back to CEMA to respond to the concerns that these groups had on their departure.
Managing a multi-stakeholder organization is very challenging, and how CEMA responds and manages this multi-stakeholder organization could be a major contribution to projects in the future. Establishing this network and making it viable and effective are ongoing challenges that we will respond to.
There have been three third-party reviews of CEMA over the last couple of years. All are available to the public on our website now.
The CEMA board, through its management committee, has held a retreat recently to deal with the issues raised in these reviews. The interesting fact is that the majority of recommendations were not directed at CEMA itself, but towards the regulators and how they interact with CEMA.
The CEMA management committee, with the approval of the board, is looking at how we can reshape CEMA to make it more effective, more efficient, and more attractive for organizations to participate in--and for those that left, to come back. I say this because one of the key messages we received from all of the organizations who left CEMA is that they all left the door open. They made suggestions for change and they put the challenge to CEMA.
CEMA has also recently teamed up with a joint federal-provincial regulator committee—over the next few months, between now and the end of the year—to look at this reshaping of CEMA and to make recommendations to the members of CEMA on how that reshaping may take place, because it's only the members of CEMA who can initiate that change.
CEMA is no different from any other non-profit organization. It relies on outside funding. To date, the majority of that funding has come from industry, and there's a blessing and a curse on that part. The blessing is that it's a fairly secure form of funding and it has come on a regular basis. The curse is that when the majority of your funding comes from one direction, there are perceptions that maybe it has more of an influence than it really does.
I recently went to Ottawa to meet with our five federal agencies that are members of CEMA to deliver the message to them that CEMA needs their help in two areas. One, they need to take a very active participation in the reshaping of CEMA to make it more effective, which would include a higher level of involvement in our management committees, our membership, and also in our working groups. We understand the challenges when the expertise is in Ottawa and meetings are held in Fort McMurray, Edmonton, and Calgary. There are financial challenges to this, but we feel it's very important, and we conveyed that message.
The other part of that message was to convey the uncertainty in these uncertain economic times in the petroleum industry about whether the level of support from industry will be maintained, or whether CEMA will have to rely on other sources of funding to continue its mandate, specifically from federal and provincial government agencies.
In the last two years, the provincial government has stepped up and contributed a significant amount to our annual budgets. The federal contributions to date have been rather minimal. We were very happy, though, to have announced very recently that the Department of Fisheries and Oceans has assisted us greatly by taking over the funding of a couple of our projects, and also by providing in-kind support to one of our major fisheries studies, amounting to support at a level of $350,000.
Also, in responding in part to some of the criticisms of CEMA and the cumbersome decision-making and transparency of CEMA, the CEMA board has adopted two new policies in a very short period of time in the last few months. We now have a new decision-making policy wherein the consensus-based model is used, mainly on recommendations going out the door of CEMA to the regulators. And on a number of internal process questions, we now operate more on a majority vote.
The latter isn't an effort try to minimize anybody around the table or to try to target groups, but to try to be more effective. One of the criticisms that CEMA took from the phase one instream flow needs study was that we didn't meet the deadlines, that we didn't do our job. I could look at it a different way: we finally realized there were limitations to what multi-stakeholder groups could do. And instead of continuing to beat each other over the head with baseball bats when we've completed 95% of the job, the decision was made that it's actually the regulator who makes the final decision, so let's turn the final product over to the regulators and let them make that decision. But that decision was based on 95% of the work being completed by CEMA. CEMA completed the research; it completed the studies that contributed to that.
One of the things that was missed this morning is that the phase two study is being coordinated by CEMA. We're the ones who had to go out and raise the funds to complete that study. We had to change some of our internal policies to allow groups like the World Wildlife Fund to participate, because we had a policy that if you weren't a member, you didn't participate.
So we are changing. We are trying to respond to make this multi-stakeholder group more responsive.
We have also just completed a release of information policy that will result in the release of the majority of information CEMA has, including reports, databases, and so on. There are some restrictions, as there are pieces of data we are not free to release. One example is that we have collected a fair bit of information on traditional environmental knowledge from various first nation groups, with whom we have legally binding agreements that we cannot release that information without their approval.
In our release of information policy, led by industry members, we are not trying to recover costs on these studies. If the information is being used for research, whether by an NGO, a research institution, or a government agency, we should be prepared to release that data. The only restriction would be that if it were going to be used for a commercial venture, there might then be opportunities for CEMA to recover some of its costs.
On the issue of water, the majority of the water issues in CEMA are conducted through our surface water working group, and their main effort is focused on dealing with the RSDS issues related to water. The surface water quantity issues include a focus on ensuring the health of the aquatic ecosystem and the maintenance of socio-economic uses of the lower Athabasca River. The main surface water task, at this point in time, is supporting the creation of that phase two water management framework for the lower Athabasca River.
It is anticipated that the final draft report will be completed by the end of this year. It will be formulated into a recommendation to the government, and we would hope that recommendation will be going forward in 2010.
The opportunity of creating a multi-stakeholder group to deal with tough issues is unique, and I think the fact that there are still 46 agencies sitting around that table trying to deal with these issues is a bit of a milestone. Yes, organizations—
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I'll be able to speak at a reasonable speed, then. That's fine.
I should probably begin, Mr. Chairman, because it sounds like I have somewhat more of a broader overview than my colleague.
Thank you for the invitation. I want to begin by emphasizing that I'm here in my personal capacity. The Canadian Institute of Resources Law does not actually take positions on public policy issues, so the views of its professional staff remain just that, their own views.
Turning to the substance of what I want to say, I'm going to restrict my comments here to two issues: first, transboundary water issues that may arise as the consequence of oil sands development; and second, some of the interjurisdictional implications arising out of new provincial approaches to natural resources management, particularly as they affect the oil sands.
I'm going to deal with the first of these issues very briefly. The federal role in transboundary water management is of relevance to this committee, it seems to me, in at least two respects.
First, with respect to the lower Athabasca, this watershed is, of course, part of the large Mackenzie basin. If one were to take the broader view and look at the likely stresses on the basin in coming years, particularly in light of possible impacts of climate change, then one is inevitably struck, it seems to me, first, by the highly deferential role that the federal government has played in the negotiation of the interjurisdictional agreement on the Mackenzie; second, by the consequent weaknesses of the agreement itself; and third, by what I think we have to say is the poor track record of jurisdictions in concluding the subsequent bilateral agreements necessary to give some substance to the master agreement.
In sum, there are important federal interests here and a clear need for federal leadership, which has largely been abdicated by the federal government over the past three decades.
A second transboundary issue the committee might want to consider relates to the federal interest that would be triggered by the use of transboundary deep saline aquifers that extend into the United States, and that would be for CCS purposes. This is not idle speculation. There are indeed just such transboundary formations that are of interest in the south of the province.
Again, there would appear to be a clear federal interest in these aquifers, but as legislation now stands, it is not clear that there's even a trigger for the federal government to initiate an environmental assessment. Put differently, would the federal government in such a situation simply leave the field to the province even though we are dealing with transboundary waters?
Turning now to the second issue I referred to at the beginning, I'd like to discuss briefly how one reconciles the nature of the federal government's constitutional responsibilities with the imperatives of modern approaches to natural resources management.
I think the challenge facing the federal government in this respect may be summed up this way. The role that our Constitution contemplates for the federal government in natural resources management is, in some respects, strong, but more importantly it is narrow, predicated primarily on a relatively small range of interests—for example, fisheries, navigable waters, and so forth.
By comparison, of course, the provincial basis for exercising jurisdiction in this field is very broad, and in the result, the proposition that the provinces should, in general, take the lead in the management of their own natural resources endowments is not seriously questioned. What is more problematic, though, is how natural resources management regimes can be structured to both recognize the pre-eminence of provincial authority and yet accommodate the federal government's constitutional responsibilities, while still allowing decisions on resource development to be made in an effective fashion.
One of the primary tools for integrating federal concerns into the process of natural resources management in recent decades, of course, has been environmental assessment. Over the years, federal and provincial cooperation on EA has enabled the federal government to introduce its specific concerns with particular projects into approval processes for projects that are primarily of provincial interest. The value of EA is beyond doubt; however, the limitations of project-specific analyses have also increasingly been recognized in recent years, particularly with respect to the recognition of cumulative effects.
To some extent, EA itself has been adapted to take account of cumulative effects. However, there has also been a move, more generally, to create different processes that take on this planning function independently of EA.
Sometimes these processes are sectoral in nature, such as Alberta's “Water for Life“ strategy. Sometimes they are broader, such as Alberta's land use framework, for which legislation has recently been introduced in the legislature. The signature of most of these new initiatives, though, is the recognition of two fundamental principles: first, that planning is best done at the landscape level, so that all interactions between humans and the natural environment are taken into account; and second, that planning exercises should be place-based, so that planning reflects the unique conditions of the area in which it is being conducted, and should therefore include a significant role for local input.
The challenge posed to the federal government by such approaches is if the nature of effective planning is that it is landscape in scope and place-based in orientation, how does that fit with the federal goal that is largely sectoral in scope, whether protecting fisheries, or navigable waters, and primarily national in orientation?
One possible response to this challenge lies in the approach that has been taken with respect to the lower Athabasca River; that is, to deal with federal interests—in this case, those primarily related to fish and fish habitat—on an ad hoc basis, and initially in the context of CEMA, and subsequently through a federal-provincial agreement on a water management framework. I won't address the merits of either CEMA or that framework at this point, though I suspect my colleague will, but I would point out that even CEMA has questioned where they stand in the face of the types of provincial planning exercises represented by the new land-use framework in its implementing legislation.
I think this is an area where the committee could provide some useful advice as to how the federal government should adapt its own role in natural resources management in light of these new and emerging provincial approaches.
Thank you.
Of course I don't represent the University of Calgary either. These are my own points of view.
My presentation will concern two areas. I will speak on the importance of an effective legislated enforcement mechanism for the water management framework, instream flow needs of and water management system for the lower Athabasca River. This is what my colleague was referring to--that is, to one of the agreements and whether there is such a mechanism.
I will also briefly discuss how critical it is that we have an effective wetlands policy covering the northern boreal forest, where oil sands mining and in situ operations are occurring, and how the oil sands or oil and gas industry have effectively blocked a consensus policy recommendation to the government.
With respect to the first issue, the water management framework, as you probably know from other submissions, oil sands operations use a very large quantity of water. As development increases, so will their water needs, and there will be more of an impact on the Athabasca River. So in an attempt to deal with these water quantity issues, the Department of Fisheries and Oceans and Alberta Environment developed the water management framework, which, among other things, determines the instream flow needs of the lower Athabasca River and sets out water management responses for the oil sands industries that are using the water.
The primary mechanism of the framework is to establish three river flow conditions: green, yellow, and red for each week of the year. So far in 2009 Alberta Environment has issued three yellow zone warnings. Both the yellow and the red zone management actions potentially require a Fisheries Act authorization, if the withdrawal or cumulative withdrawal “results in the harmful alteration, disruption or destruction of fish habitat” under subsection 35(1) of the Fisheries Act.
As well, the framework contemplates that when water supplies are limited by flow conditions, the industrial water users will cumulatively limit their withdrawals from the river to meet the targets established by the framework, and will then share the residual amount so that every industry will get some water to keep carrying on with their development.
But to protect the instream flow, it is critical that the oil sands water users, at minimum, adhere to the framework's required water management responses. There are some who indeed think that the instream flow requirements could have been set higher than they are.
So the question I raise here is what is there in place to ensure compliance? Under the Water Act, where the industry users have their rights to use water, there is nothing that would require compliance, nor is there anything under predecessor legislation. In fact, water rights are based on first in time and first in right, and each water user has the right to take their entire allocation in accordance with their licences and the terms and conditions of those licences.
What the framework is requiring the industries to do is essentially to contract out of the legislation in order to maintain the instream flow requirements in the Athabasca River. So I then raise the question, what is there to require this contracting out to be maintained?
Having looked at the 2008 industry agreement, I do not even see consideration of this mentioned in it, and it's not clear to me that it is an actual binding contract. Moreover, there is no legislation requiring this voluntary arrangement to be continued.
There are other things that have been touted as regulatory backstops. For example, there are conditions on water licences. However, if one were to look at these conditions, you'd see that the conditions are different on all the licences. Some of them I think are legally specious, in that they seem to have been added after the licences were issued, and I'm not sure if government would actually be enforcing these conditions.
In any case, in other areas the province has indicated that it will not enforce such conditions--this is for the South Saskatchewan River basin, a different basin--unless they were issued after 2005. So I'm certainly not confident that conditions on licences will do the trick.
There's also, of course, the Fisheries Act and the requirement for a Fisheries Act authorization if withdrawals will cumulatively, or I guess individually, result in a harmful alteration, destruction, or disturbance of fish habitat, or HADD. However, I think there are real issues with that as well, because unless you can pinpoint one licence, it's going to be difficult to determine who was responsible for that HADD. And in any case, it could always be authorized by the federal government, which is not going to protect our instream flows.
Finally, the agreement, the framework itself, says that it does not apply to pre-1977 water licences, because that's when the HADD provisions were put into the Fisheries Act. The pre-1977 licences are those of Suncor and Syncrude, or at least some of Suncor's licence, and they amount to about 75,000 acre-feet of water per year. I would contend that there really is no reason in law to exempt those licences, and indeed, the DFO otherwise has published a policy that says it will apply section 35 to pre-1977 structures. So it's not clear to me why they haven't amended the framework to make it clear that it also applies to pre-1977 licences.
My suggestion is that it's in the public interest, and if we're going to protect the river, we're going to have to have some effective legislated control over these licences and to maintain the industry agreement. If industry is bona fide, as it claims to be, about really wanting to adhere to the framework, it shouldn't be unhappy about having such legislation put in place.
The second thing I want to talk about briefly is the provincial wetlands policy. Since 1993, Alberta has had a wetland policy that applies to what we call the white area of the province, or the settled area of the province, and not the boreal forest where the oil sands mining is occurring. That is a no-net-loss policy, meaning that if someone wants to destroy or disturb a slough-marsh wetland, then they have to, according to the policy, restore one in some other place.
Since 1993 the government has been trying to develop a comprehensive wetland policy that applies not only to the white area, the settled area of the province, but also to the northern boreal forest and the peatlands. In May 2005, the province took a major step to this end when the Alberta Water Council was charged with the mandate to develop such a comprehensive policy and struck a wetland team, of which I was a member. I represented the Alberta Environmental Network.
We met for three years. We had numerous meetings, all-day meetings. It was a huge amount of work. During this, the NGO community made many concessions in order to reach a consensus document at the end, which I thought we had. Indeed, after we had our last meeting, the two oil and gas stakeholder organizations sent letters in and either denied they had consensus or withdrew consensus and said they could not accept the document. So that's where it stands right now, after three years.
The document now is with the provincial government and we do not have a wetland policy, notwithstanding that oil sands mining will destroy or has destroyed 80,000 hectares of peatlands. As I'm sure all of you know, these peatlands, these wetlands in the north, provide numerous water quality and water quantity functions, as well as provide for ecosystem health.
My recommendation--and I don't know what power you would have to do this--is that somehow we really need to get this policy in place before there are more approvals. My hope would be that it would apply to approvals under consideration and that the government no longer delay on this.
Thank you very much.
To begin, I have just a couple of comments. Thank you for being here.
You initially touched on carbon capture and storage, on the impacts of the direction in which Canada and the United States are heading, and on some of the transboundary water issues.
The two countries in the world that are proceeding with and investing heavily in that technology of carbon capture and storage are Canada, at a little over $3 billion, and the United States, at about $3.5 billion.
Also, with the clean energy dialogue that's ongoing with the new Obama administration--it's moving very quickly, preparing for Copenhagen in December but also on harmonizing an approach--Canada and the U.S. will be on a parallel path to meeting a number of environmental issues. I'm sure you're aware of it.
There was a question, I think, on what power this committee has. Our committee is on a fact-finding trip. We will debate, when we get back to Ottawa, what we've heard over the three days. The committee meets twice a week. The committee has a very busy agenda. We are scheduled to discuss the water issues and the oil sands in the fall. It may be the fall or it may be sooner; we'll see.
We hopefully will reach consensus. If we do reach consensus--there are diverse opinions around this table--then recommendations could be made. Those recommendations then would be forwarded on to the House of Commons, where it would be debated. Those recommendations could go to government for changes.
That's just in answer to your question.
I want to thank both of you for your presentations. They were thought-provoking. We'll see where we go from here.
Thank you.