RNNR Committee Report

Introduction

The development of the oil sands and the rapid expansion of the industry pose tremendous challenges on many levels. First, the industry must raise large amounts of capital to deal with increasing capital and energy costs, if only because of the nature of this type of industrial activity. Added to that is the growing difficulty of recruiting specialized and non-specialized workers. There are equally great environmental challenges, particularly those involving the boreal forest, water use and treatment, greenhouse gas emissions, the evaluation of cumulative impacts, land reclamation, etc. Issues relating to the local infrastructure (housing, roads, drinking and waste water), health services and the Aboriginal populations also generate numerous challenges.

Natural Resources Canada acknowledges that, despite all the economic advantages associated with oil sands development, some aspects remain problematic, particularly the environmental footprint, the increased need for natural gas, the capacity of pipelines and refineries, and the availability of qualified workers, a problem that is considered extremely crucial.

As I mentioned at the start, there are some important issues raised by the development of the oil sands—perhaps most importantly, the environmental footprint, but also what it might mean for natural gas markets, and whether the pipeline capacity is adequate, whether there is enough labour, and so on.¹

The House of Commons Standing Committee on Natural Resources believes in achieving a balance among three main factors: the resource’s potential, the necessary investment and the environmental effects. In that regard, the Committee subscribes to a scenario evoked by the President of EnergyInet, Michael Raymont, to wit:

… we can enter an era of responsible and reliable energy supply. All we need to do is focus on the responsible development of conventional energy resources, with particular emphasis on our lower carbon footprint and reduced collateral resource requirements. By this I mean water and other things necessary to produce energy. We should accelerate the development of unconventional and alternate sources of energy, including renewables, while emphasizing technology development and deployment. We also need a responsive regulatory environment and, equally important, a more certain and stable business environment, so that the private sector can make and deploy the technology necessary to obtain environmentally benign forms of energy production and usage.²

The Committee heard experts say that the industry already has all the technology needed to produce non-polluting energy. What is really missing are the conditions that would encourage the private sector to invest in that technology.

In the update of its 2004 report,³ the National Energy Board (NEB) reviewed its initial assessments of the current rapid growth in oil sands development. For the purpose of its analysis, the Board considered a reference scenario that envisages an increase in daily production from 1.1 million to 3 million barrels a day by 2015. The analysis takes account of factors that tend to precipitate or encourage growth, such as the high price of crude, the growing global demand for energy, technological innovations, the great stability of Canada’s investment climate, and the vast U.S. market. These growth factors are counter-balanced by the need to develop markets and build pipelines, the increase in capital and labour costs, the increase in operating costs, the shortage of labour, inadequate infrastructure, and the need to manage the environmental impacts of development projects.

Cost increases

Many of the witnesses that the Committee heard insisted that the pace of oil sands development in the next few years would depend in large part on the industry’s capacity to deal with rising costs and the availability of qualified workers. Some, including the Assistant Deputy Minister for Energy Policy at Natural Resources Canada, Howard Brown, feel that the labour shortage could even become the main factor limiting that growth. Others feel that it is various market factors, taken together, that could put a damper on the effervescence currently on display in Alberta’s oil sands sector.

Given the strength of the economy in the Canadian West—driven by the development of oil and gas, potash, uranium, municipal and Olympic infrastructure—a certain number of oil sands projects have already been delayed or extended over a longer period because the companies themselves recognize that there are problems related to costs and other factors that do not operate in their favour.⁴

Labour

The consensus among those who appeared before the Committee is that the availability of workers is one of the most serious problems for oil sands development. There has already been some slowdown in the development of new projects, largely because the labour shortage in Alberta is forcing costs up. The labour shortage has become so serious that the industry labour forecasts had to be revised between fall 2005 and fall 2006. The new data presented by the Canadian Association of Petroleum Producers indicates that the employment peaks for industrial construction projects in the oil and gas sectors have shifted by some two years and increased from 32,000 to more than 34,000 jobs.⁵

Since Alberta has only a limited number of qualified workers, the oil sands sector has a problem not only finding the qualified workers it needs, but also attracting them to the region of Fort McMurray. Moreover, this problem affects not only qualified and specialized labour, but every sector of the economy, notably the services and house‑building sectors. In fact, when any new oil sands development project is approved and begun, it brings new workers to the Fort McMurray region, thus increasing the pressure on the housing industry. For several years now, there has been an observable increase in labour mobility from eastern Canada, Newfoundland and Labrador and the Maritimes in particular, to Alberta. Some even fear that this westward movement could result in new labour shortages in the East.

The labour shortage forces the industry and governments to develop new approaches. Among these, apprenticeship programs have had some success producing apprentices, and particularly recruiting people from the growing Aboriginal population of Alberta, Saskatchewan and Manitoba. In the oil sands industry, companies are requiring the equivalent of Grade 12, which helps raise the level of education among Aboriginal people and make them more employable. Vocational programs in Aboriginal communities are essential in this respect.

Immigration is also being called on to play an increasingly large role. Until now, companies have found almost all the workers they need in Canada, but the industry’s future expansion will make immigration an unavoidable necessity. The federal government can play a major role here; for example, the Department of Citizenship and Immigration has opened what it calls “temporary foreign worker units” in Calgary and Vancouver, as part of a pilot project to meet labour needs. As the President of the Fort McMurray Chamber of Commerce, Mike Allen, mentioned, the governments of Canada and Alberta signed an agreement in May 2004 to allow temporary foreign workers to enter the country to meet the urgent need for qualified workers for oil sands projects. The federal government recently announced changes to the Temporary Foreign Workers Program to speed up hiring when there are no Canadian citizens or landed immigrants in Canada to occupy the vacant positions. Furthermore, the range of jobs was expanded to some 170 different professions, which demonstrates the extreme pressure on the labour market in the region. There are still challenges to be met in terms of recognition of foreign degrees or helping immigrants with prior education to develop their skills sufficiently to meet Canadian standards.

Based on the evidence heard, the Committee recommends that the federal government, in cooperation with the Government of Alberta, renew efforts to fill the shortages of specialized and non-specialized workers in the oil sands sector.

The Committee was also made aware of another aspect of the labour problem. The shortage of, and thus demand for, qualified workers is not limited to the oil sands sector; it extends to certain federal government agencies responsible for enforcing energy legislation. That is the case, for example, with the National Energy Board, which lost 55 employees last year from a staff of 300. Most of them left for the private sector, which was able to respond more quickly to their salary and other demands. Given the growth in the oil sector and the number of projects that the Board must assess, the need to retain its qualified staff in order to be able to handle and study extremely technical questions becomes an enormous challenge. The main difficulty is not to recruit talented and competent young employees but rather to retain and attract experienced employees and managers. This phenomenon is not limited to the NEB but also affects Natural Resources Canada, a department that does a great deal of research and therefore requires a highly qualified staff.

The Committee recommends that the Department of Natural Resources carry out a study and propose a human resources action plan to retain experts within the Department and mitigate the brain drain to the oil and gas industry. The Committee recommends that the federal government, and Natural Resources Canada in particular, develop and implement measures to ensure that the highly qualified scientific personnel needed to carry out its mission and its various mandates are retained and replaced when they leave.

Capital costs

It is clear that labour availability has a real impact on the industry’s capacity to continue developing the oil sands, primarily because of the rising costs engendered by labour shortages. However, labour is by no means the only area in which costs are rising. Indeed, the growth of the oil sands industry is significantly dependent on the cost of material, energy and capital. As Mr. Jim Carter, President and COO of Syncrude, pointed out, all this affects the economic evaluation of projects.⁶ When costs are rising, promoters tend to wait longer before making decisions. Already, some projects have been pushed back and, if the cost of crude oil continues to fall and costs continue to increase, it is likely that we will see more projects delayed or abandoned.

Investments costs, for steel alone, have increased considerably since 2003. For example, a 100,000 barrels a day oil sands project that cost around $3.3 billion then might cost $6 to 10 billion today, primarily because of the quick and steep rise in the world price of steel. The rising cost of steel affects construction projects throughout the world, while labour availability is a problem that primarily affects North America.⁷

The projections for oil sands development by 2015 will require capital investments estimated at $125 billion in order to increase production from 1 million to between 3 and 3.5 million barrels a day. The extent of the projected investments in the oil sands is so great that companies and their shareholders may become more hesitant without assurances of a worthwhile return on their investment and an acceptable degree of certainty in the investment cycle.⁸

Another important aspect of the deployment of new projects is the flow of the new production to the markets. Indeed, “if the production does grow in the manner in which it is predicted to grow, there is a need for additional transportation in order to bring the oil that would be produced to market.”⁹According to NEB estimates, the current system of pipelines is expected to reach full capacity in 2007, which is why something must be done very quickly about the distribution on certain pipelines or to increase transport capacity by building new pipelines. At present, bitumen and synthetic crude are marketed primarily in Chicago, and to a lesser extent in Colorado and Washington State. To maximize economic performance, producers need markets that are as diversified as possible.

Numerous pipeline projects are currently under development, and once some are completed it should generate sufficient capacity in the next few years to transport bitumen and synthetic crude. One of these projects is a major increase in the capacity of the Trans Mountain Pipeline, which runs from Alberta to Vancouver. This will make it possible to send larger quantities of oils sands production to refineries in the Puget Sound region of Washington State. Other projects involve the Chicago region that will send products to the U.S. Gulf States. Finally, a third area affected by the construction of new pipelines would be between southern Alberta and Wyoming and Colorado.¹⁰

It is not enough to transport bitumen and synthetic crude; such products must also be refined. In this case, it is not the overall refining capacity that is the problem but rather whether refineries are equipped to process bitumen and produce synthetic crude. There are a number of projects under way in the United States and Canada to transform refineries in order to increase their capacity and ensure that they are able to process larger quantities of the product extracted from the oil sands. One example is the Petro‑Canada refinery in Edmonton. It should be noted that no refineries have been built in Canada in 20 years or in the United States in 30 years, since the industry limited itself to increasing the capacity of existing refineries. Although questions still arise about the wisdom of investing in the construction of large refineries, some projects are under way, one in eastern Canada and the other in the West.¹¹The decisions that are made about pipelines and refineries essentially are related to the capacity of the markets to absorb oil sands production if it is more than 2 million barrels a day higher than current production levels.

The industry in Canada already upgrades 800,000 barrels a day out of a total production of 1.1 million barrels or some 72% of total production . The plans to expand existing plants and to build 10 new upgrading facilities should give Canada a domestic upgrading capacity of 3 million barrels, which would be sufficient to transform roughly 85% of an estimated production of 3.5 million barrels a day. While not all oil sands upgrading will be done in Canada, industry representatives told the Committee that the vast majority should continue to be done here.¹² However, it should be noted that the processing or upgrading currently done in Canada is basic, being limited to transforming bitumen, the least valuable product, into synthetic oil. Some feel that there is no reason we could not refine synthetic oil to produce gasoline, diesel and other petrochemical products.¹³

Increase in the consumption of natural gas

Along with the use of water and reduction of emissions, the use of natural gas in the extraction and processing of oil sands represents one of the greatest challenges facing the industry. Some of those who appeared before the Committee were quite categorical about the increased use of natural gas for the development of oil sands deposits. For example, Mr. Michael Raymont of EnergyInet feels that using natural gas as a fuel in oil sands development is “like turning gold back into lead.” In fact, the natural gas used as a fuel to extract and upgrade bitumen is a relatively clean fuel. It is used in the oil sands primarily for historical reasons, that is, because there was an abundance of gas in this region 40 years ago. Today, however, we realize that this fuel can be put to better use, particularly given the price levels in recent years. The need to find an alternative to natural gas is made all the more pressing by the belief that there might not be enough to produce the projected three to five million barrels a day from the oil sands.¹⁴

Current estimates say that it takes between 500 and 1000 cubic feet of gas to produce a barrel of synthetic oil, depending on the quality of oil that is produced. In monetary terms, it takes between $3.50 and $7.00 worth of gas to produce a barrel of oil. According to the Canadian Association of Petroleum Producers, natural gas is the most important operating cost in an oil sands plant, which is why the industry is looking for replacement fuels. NEB projections indicate that natural gas requirements for the industry could reach 2.1 billion cubic feet a day in 2015, compared to the 0.7 billion cubic feet a day used in 2005.¹⁵From a broader perspective, primarily that of North American consumption of natural gas, Natural Resources Canada estimates that the oil sands currently represent roughly 1% of total consumption in North America and predicts that this percentage will remain relatively stable over the next 15 years. The Department does not feel that 1% is a negligible amount by any means, but it is felt that this is not a sufficient quantity to have a decisive impact, positive or negative, on the natural gas market.¹⁶While the impact of the general natural gas market was not part of the study, the Committee recognizes that there could be an impact on the use of other fuel choices if the 2.1 billion cubic feet per day of natural gas was available for other uses.

In addition to strictly economic considerations, other elements are likely to influence the pace of development and replacement of natural gas, particularly future environmental and atmospheric emissions regulations. Already, a number of technological solutions are being studied to replace natural gas in the production of steam for in situ development projects or of hydrogen for upgrading bitumen. Aside from cogeneration, which generates steam and electricity at the same time, one of the most promising technologies mentioned before the Committee is gasification, of coke, coal or bitumen residues. According to Dr. David Keith,¹⁷gasification, with CO₂ capture and storage, is more competitive in oil sands operations—which require both heat and hydrogen—than in the electricity sector. Roughly speaking, gasification involves breaking materials down into their constituent elements in a closed system and reassembling these elements with other elements—such as oxygen—in order to make different products. If the gasification process generated a great deal of CO₂ during oil sands operations, it would be possible to separate this flow and then store it. In a recent report prepared for the Minister of Natural Resources Canada, gasification technologies were identified as the first of four major priorities, the second being storage, on which the federal government should focus its attention in energy research.¹⁸

Gasification will soon be used in the Long Lake Project, where two companies, Opti and Nexen, have begun building in situ oil sands development facilities that will produce between 70,000 and 150,000 barrels a day. Natural Resources Canada says that gasification of residues, such as the coke that the industry is currently storing at development sites, is probably one of the most promising technological developments for processing residue with no other use into synthetic natural gas. In fact, the gasification of coal and residues is not a new technology, but it has been improved over time to the point that it is now more commercially viable. Many say that it would reduce the environmental footprint of oil sands development because of the capacity to extract carbon dioxide and certain other atmospheric pollutants (particulates, NOx and SOx, etc.).¹⁹

Another possible replacement for natural gas that was mentioned several times during the Committee’s hearings is using nuclear energy to produce steam and electricity. The Committee heard from one of the proponents of this approach, Mr. Wayne Henuset of the Energy Alberta Corporation.²⁰According to its proponent, nuclear energy has the advantage that it does not emit CO₂ and would be cost competitive with natural gas. If the regulatory process to authorize a CANDU 6 plant began in spring 2008, it would take another eight years, or until 2016, before it was fully operational. The energy produced by such a plant, which could produce some 740 megawatts of electricity, would be sold either through direct agreements with an off-taker or through an open bidding process.

Some feel that the nuclear option has its share of drawbacks, and that is not even considering the question of how to manage the resulting radioactive waste. First, they point out the limitations on the distribution of hot water or steam over great distances. Thus, hot water could be sent over roughly 75 kilometres, but steam over only 25 kilometres. As well, it is estimated that a plant of roughly 600 megawatts could supply a processing plant producing 60,000 barrels of synthetic crude oil a day. Given that, it would take almost 20 reactors to meet the forecast production needs as of 2015.²¹For others, the main problem is that classic nuclear plants are too big for oil sands development and that smaller plants would have to be considered, on the order of 100 megawatts, a size better adapted to the characteristics and needs of individual oil sands development projects.²²Others think that gasification technology, coupled with CO₂ capture and storage, is more competitive than nuclear energy for the oil sands. This is because it can generate hydrogen, which nuclear energy cannot do as cost effectively.²³

Based on the evidence heard, the Committee recommends specifically that Natural Resources Canada, together with its various partners, step up its R&D efforts to stimulate innovation in the area of replacing natural gas with clean sources as regards greenhouse gases in the extracting and processing of oil.

The Committee further recommends that the government implement a joint public/private task force to find solutions as quickly as possible to reduce the use of natural gas in oil sands production, thereby conserving this resource for a more valuable use.

Furthermore, the Committee recommends that no decision be made on using nuclear energy to extract oil from the tar sands until the repercussions of this process are fully known and understood.

The introduction of new technologies

The solution to many of the challenges facing the oil sands industry, such as replacing natural gas in extraction and processing, reducing emissions and reducing the impact on water, will require the development and introduction of new technologies in the relatively short term. As mentioned previously, a number of these technologies are now beyond the research stage and are already pilot projects or semi-commercial facilities. The Committee heard convincing and enthusiastic evidence about the technological possibilities in the oil sands sector. Some experts say that technology will be able to solve many of the problems, if it is used properly and if the government sends the right signals. Technological innovation could be the key to increasing oil sands production in a responsible manner. However, some obstacles remain and will have to be overcome quickly, primarily with government support.

Some feel that the innovation system is not working: “We put billions of dollars into the front end of research and development, and we are not seeing the benefits coming out the back end.” There are, the Committee was told, gaps in the main links of the “innovation chain,” such as in the transition from basic R&D to implementation, by building a pilot plant or demonstration plan or doing marketing; these are the essential elements in the under-funded portion of the innovation chain. Ideally, it should be three parts private investment to one part public investment. In Canada, the ratio is 1.18 to 1; something must therefore be done to encourage the private sector to do more R&D and improve this ratio.²⁴ Representatives of the oil industry told the Committee that the energy sector as a whole currently spends $720 million a year on R&D, all activities included.²⁵More specifically, companies in the oil and gas sector invest only 0.36% of their revenues in research and development,²⁶ which represents less than a tenth of the Canadian industrial average.

This Committee is concerned that the public sector has borne too great a proportion of oil sands research and development in comparison to the private sector. This Committee therefore calls upon the industry to increase its commitment to research and development to meet the Canadian industrial average, and further calls upon the federal government to shift its research focus to emerging renewable and sustainable technologies.

While federal spending on research and development in the energy sector has declined by 70% from its peak during the 1980s,²⁷the federal government, and Natural Resources Canada in particular, are nevertheless active in energy R&D. In fact, Natural Resources Canada has very clear responsibilities regarding research, development and innovation and has been active in this area for many years, particularly through the network of the Canada Centre for Mineral and Energy Technology (CANMET). One of the three main centres in the Energy Technology and Programs Sector (CANMET‑CTEC), the Devon centre in the Edmonton region has concentrated on oil sands and crude oil since 1995. The Devon Centre, which has 80 to 120 scientists and engineers depending on the projects, works in close cooperation with the industry and universities to resolve various problems and help ensure that the oil sands are developed in a more responsible fashion. Natural Resources Canada spent a total of $212.9 million on research and development in 2005-2006, including $81.7 million for the energy sector. In other words, some 40% of total R&D spending went to energy, including a significant proportion to projects with an environmental bent.²⁸At the CANMET Centre in Devon, over 90% of the R&D work is related to the environmental aspects of the oil sands, the goal being to develop new technologies that consume less energy, require less water, produce fewer emissions, etc. Some of this technology is already at the implementation stage.²⁹

While there is diverse opinion on the future development potential of the oil sands, an important question is: can innovation and technology keep pace with the frantic growth and development of the oil sands sector? Of course, the investment in research and development is designed, in part, to improve environmental performance, but the industry is also looking for a cost payout. Take greenhouse gas emissions; the industry will be inclined to invest primarily in energy efficiency, rather than CO₂ capture and storage, which does not necessarily have an economic benefit. On the other hand, if there is a clear signal from the government and some form of cost accounting for emissions reductions, the dynamics of investment in research and innovation may quite likely change as a result.³⁰

Many of those who spoke before the Committee feel that the government has an obligation to share the risks of innovation and implementing new technologies. That does not necessarily mean that the government must itself be involved in every facet of technological innovation, but it must at least find solutions to ensure that the risks assumed by the private sector are mitigated by certain government actions. There is no question that the government must do something to encourage companies that want to begin using new technologies and that want to make long-term investments by reducing the obstacles to innovation as much as possible.

On the basis of the evidence heard, the Committee recommends that Natural Resources Canada acknowledge and follow up on the first two priorities identified in the Report of the National Advisory Panel on Sustainable Energy Science and Technology, that is, gasification technologies and CO₂ capture and storage technologies.

Moreover, recognizing that the federal government plays a recognized and indisputable role in R&D, the Committee recommends that it maintain its participation as it relates to the various facets of oil sands development.

Apart from R&D, some of the evidence presented to the Committee showed that there are serious shortcomings in Canada’s innovation system. Concrete measures must be developed and implemented, particularly in the energy and environmental sectors.

Environmental impacts

Alongside the constraints and challenges being faced by the oil sands industry, environmental impacts represent an equally great, if not greater, challenge in terms of the development of this huge resource. The main environmental challenges are impact assessment, greenhouse gas emissions and other pollutants, water use and treatment, land reclamation, etc. Although some technical advances have been made, much remains to be done to reduce the impact of extracting and processing the oil sands.

1.  Federal and Provincial Government Assessment Processes

As previously described under the heading of the respective roles of the federal and provincial governments in developing the Alberta oil sands, environmental issues are a shared jurisdiction whereas natural resource management is a provincial jurisdiction. One of the federal government’s roles is to conduct environmental impact assessments for a number of environmental activities and aspects. Thus the triggers for federal involvement in environmental impact assessment for oil sands development projects relate to protection of the environment, waterways, fisheries and Indian lands.

When they appeared before the Committee, representatives of the Canadian Environmental Assessment Agency (CEAA) explained that at the federal level, responsibility for assessments rested with the authority responsible for the decision on the project under review. For oil sands development projects, it is mainly Fisheries and Oceans Canada and Transport Canada that intervene, whereas Environment Canada, Natural Resources Canada and Health Canada act as experts to contribute to the analysis process. In 1993, the federal government signed the “Canada-Alberta Agreement for Environmental Assessment Cooperation”, under which a single joint assessment allows both authorities to discharge their legal obligations by pooling information required by the developer and to hold public hearings, where applicable. This form of “one-stop shopping” mainly prevents duplication, with each government retaining legislative authority in their areas of jurisdiction and remaining responsible for environmental assessment decisions.³¹ At the provincial level, Alberta Environment and the Alberta Energy Utilities Board contribute to this harmonization process in oil sands development projects.

According to the CEAA, the review of environmental impacts also includes the cumulative environmental impacts that the project, together with other projects or activities, may cause to the environment. It also factors in or recommends measures that are achievable both technically and economically to mitigate significant negative environmental impacts of a project. Under federal environmental assessment regulations, oil sands development projects of over 10,000 m³ per day are automatically subject to a comprehensive study, and if the Minister responsible requires, a review panel. To date, the Millennium Project was comprehensively studied in 1998, whereas the more recent Jackpine, Horizon, Kearl and Muskeg projects were assessed by a joint review panel. With the exception of the Kearl project, on which the panel is to report in March 2007, the Jackpine, Horizon and Muskeg projects all received the approval of the panels assigned the task of assessing them, but were subjected to a series of requirements and conditions such as monitoring fish and sedimentary organisms, as well as water quality and the health of Aboriginal populations affected by these projects.

Although the question of the cumulative impact of all oil sands development projects was taken into account in the federal and provincial assessment processes, hearings held by the Committee revealed a degree of perplexity among several stakeholders both about the role of each government authority and the comprehensiveness of this stage of the assessment process. Several witnesses suggested that in terms of the assessment of cumulative impacts, the authorities tended to give too much credence to others and hence to restrict their level of involvement in this area. Some felt that the scope of the assessments had been very narrow in the past, so much so that the federal government is not involved in an assessment process that would truly factor in all of the impacts, including transborder pollution, greenhouse gases, etc.³²However, as Dr. Mary Griffiths of the Pembina Institute pointed out, “That’s where the federal government still does have a role, and maybe it could exercise that role with more enthusiasm than has been apparent in the past. […] At the moment, a lot of it is discretionary. Sometimes the Department of Fisheries and Oceans will not take such a powerful opportunity as they might, because of the discretion. I think there’s been reluctance by the federal government to get too involved.”³³

Part of the problem with assessing cumulative impacts probably stems from the existence of the Cumulative Environmental Management Association (CEMA), a multipartite, consensus-based organization of representatives from industry, environmental groups, Aboriginal peoples, and municipal, provincial and federal governments. The mandate of this broad group is to try to assess cumulative environmental impacts throughout the Wood Buffalo region. Some feel that one of the CEMA’s problems is that it works within a multisectoral, multi-stakeholder mechanism that requires consensus.³⁴ Moreover, there is nothing to indicate that the CEMA has a legislative mandate, because it is a not-for-profit non-government organization that was established in June 2000 to provide a forum to various stakeholders who wanted to discuss development-related environmental problems with a view to resolving them.³⁵

Despite the CEMA’s role and the important contribution of its work to date, the Committee’s view is that its role is complementary to the legislative responsibilities of the federal and provincial governments with respect to the assessment of cumulative impacts.

In view of the level of development reached in the Wood Buffalo region and the many projects that are either already underway or planned, the Committee recommends that the federal government, working together with the Government of Alberta, undertake a comprehensive assessment of the cumulative impacts of oil sands development projects already underway and planned for the future. The Committee further recommends that the federal government, through in-house resources or through a specific mandate to an organization, conduct a full and detailed assessment of the socio-economic and environmental impacts of oil sands activities, analogous to the macroeconomic analysis conducted by the Canadian Energy Research Institute (CERI) to cover a 20-year period (2000-2020).

Moreover, this Committee calls upon the Government of Canada to employ existing legislation such as the Canadian Environmental Protection Act (CEPA) and the Canadian Environmental Assessment Act (CEAA) in a more comprehensive way to address such environmental concerns as trans-boundary air pollution, greenhouse gas emissions, and harm to waterways and fisheries. Use of such legislation should, wherever possible, be done in cooperation with the province, and should respect areas of provincial jurisdiction.

In the fall of 2006 the Government of Alberta launched a multilateral consultation on the oil sands with the federal government as a participant. It has been argued that this constitutes a high-level regional environmental assessment on the basis of which the Alberta government is attempting to determine the impact of development in the northern part of the province. Clearly the findings of the research and consultations conducted by the Oil Sands Multi-stakeholder Committee would make a genuine contribution to an exhaustive assessment of the cumulative impacts of oil sands development projects.

2.  Greenhouse Gas Emissions

The major environmental concern with respect to oil sands development, apart from issues related to the use of water, are greenhouse gas emissions and other pollutants. Indeed, increased production of bitumen and synthetic crude oil over the last decade has led to a substantial increase in emissions, making this industry sector the most rapidly growing source of emissions in the country. Scenarios in which production is scheduled to accelerate over the next 10 to 15 years are worrisome unless measures to reduce emissions are put in place.

Owing to the amount of energy required to extract bitumen from the oil sands and increase its quality in order to produce synthetic oil, the volume of pollution attributable to the greenhouse gases released per barrel is approximately three times higher for the oil sands than for the production of conventional oil. The production of greenhouse gases is not solely the result of heavy energy consumption, but also from the vapour released from solvents used to mobilize the oil. Some of these solvents act as a catalyst on global carbon dioxide emissions.³⁶ In view of the significant planned increases in oil sands production, this resource is the most rapidly growing source of greenhouse gas emissions. According to the Pembina Institute, the oil sands could account for half of the increase in greenhouse gas emissions in Canada between 2003 and 2010.³⁷

At the moment, the Pembina Institute estimates greenhouse gas emissions in 2005 at approximately 37 megatonnes, compared to 23 megatonnes in 2000; in fact, emissions have doubled since 1995.³⁸ According to the NEB 2006 update, total emissions could reach 67 megatonnes per year by 2015—some say that this level will be reached by 2010—if production reaches 3 to 3.5 million barrels per day.

Significant progress has been made in reducing the intensity of greenhouse gas emissions by oil sands operators. Indeed, the intensity of greenhouse gas emissions per barrel of oil produced decreased by more than 20% between 2000 and 2005, but this was offset by the overall increase in production, as a result of which the total volume of greenhouse gases emitted into the atmosphere has continued to increase each year.³⁹ Even though the industry is continuing to improve the energy efficiency of its bitumen extraction and processing methods, including by reducing or replacing the use of natural gas, there appears to be agreement about the fact that it is essential to introduce CO₂ capture and storage technologies to reduce overall greenhouse gas emissions.

3.   Carbon Dioxide Capture and Storage

The capture and storage of sulphur in treatment processes is already being successfully practised at a number of facilities, as evidenced by the huge piles of solid sulphur observed by members of the Committee at the Syncrude operations site. A number of observers feel that CO₂ capture and storage technologies have reached a level of maturity that would justify their use on a large scale. Nevertheless, some barriers remain to be overcome, both economically and technically.

According to Natural Resources Canada, there are now commercially viable CO₂ capture and underground storage processes because the underground storage of carbon dioxide increases the recovery rate of oil from wells, which largely offsets the additional cost. The Department has been working closely with several other government, industry and academic partners on in the Weyburn Saskatchewan International Energy Agency (IEA) project to monitor and store carbon dioxide, which is now in the second phase. This major project involves injecting a considerable quantity of carbon dioxide in the subsoil to significantly increase oil production. For this project, however, the CO₂ comes from U.S. coal gasification facilities in North Dakota, which is leading many observers to believe that the same could now be done in Alberta by capturing CO₂ from the oil sands.

In the specific case of the oil sands, the CO₂ capture technology already exists, but the gases emitted from the stacks are already at atmospheric pressure, and there is also the risk that compressing it into a usable form could produce CO₂; it is also a very costly process. In fact, the industry feels that it could cost $50 to $60 per tonne, and companies involved in enhanced oil recovery say that they cannot pay more than about $20 to $25 per tonne.⁴⁰It is therefore necessary not only to improve CO₂ capture technology at source, but also to send large quantities to the sites where it will be used.

According to the NEB, a special dedicated CO₂ pipeline from Fort McMurray to major deposits of light oil or coal gas (natural gas) in central Alberta to encourage the capture, storage and use of large volumes of CO₂ is necessary to enhance the extraction of oil and gas, for example in the oil fields of Pembina or Midale (Williston Basin). There have been various proposals for the construction of such pipelines, including those from Penn West, Apache, and Kinder Morgan. Once the CO₂ has been transported to the emission sites where they would be used, there is a risk of rapidly reaching the usable capacity in the enhanced recovery of oil and natural gas deposits. The evaluation carried out by the Alberta Geological Survey reports the cumulative capacity of Western Canadian reserves at 3.2 Gt of CO₂ for gas deposits and 560 Mt for oil deposits.⁴¹That is why many studies have looked into various forms of straightforward CO₂ storage deep underground.

The UN Intergovernmental Panel on Climate Change (IPCC) considers the capture and storage of CO₂ to be an interesting option among the mitigating measures to stabilize the concentration of greenhouse gas in the atmosphere. According to IPCC, current methods could capture from 85 to 95% of the CO₂ processed in a capture facility, but in order to do so, 10 to 40% more energy would be required to capture it and compress it. In the context of an in-depth analysis of CO₂ capture and storage techniques, and of sequestration options around the world, the IPCC found that deep saline aquifers were preferable because the carbon dioxide chemically changes with saline water, becoming denser and sinking to the bottom. So the risks of having any of it come back to the surface and presenting a hazard or contributing to greenhouse gas emissions again, would be very low.⁴²

According to various witnesses heard by the Committee, the geology of the western sedimentary basin would appear ideal for the permanent sequestration of CO₂, particularly in deep saline aquifers. However, this approach has a high cost to the industry; hence the urgent need to find mechanisms that would enable the private sector to internalize these external factors. The Pembina Institute is very interested in the potential represented by the capture and storage of CO₂. In a recent report⁴³the Institute reports an analysis of what it would cost oil sands operators to make their development carbon neutral or to achieve zero net greenhouse gas emissions by 2020. According to the Institute’s estimates, it would cost between US$1.76 and $13.65 per barrel for carbon neutral production to be achieved, and this is without including the possible sources of revenue related to enhanced oil recovery or the likely cost reductions that would stem from improvements in technology after companies begin to use it.

The industry is showing a keen interest in this technology, as evidenced by the establishment in 2005 of the “Integrated CO₂ Network”, or ICON Group, an alliance of 12 major Western oil and gas companies, to study a large-scale project on sequestration in geological formations (underground saltwater groundwater deposits and depleted oil and gas reservoirs). CO₂ captured and stored in this manner would not come solely from oil sands extraction processes, but also from coal, oil and natural gas electrical generating stations, in addition to refineries and other oil and gas processing centres. The group feels that the project being studied could store approximately 20 megatonnes of CO₂ per year, but adds that the main barrier to the implementation of the technology is the high cost, estimated at between $30 and $50 per tonne of CO₂. The evidence heard by the Committee made it clear that the industry was not prepared to assume the costs of implementing the CO₂ capture and storage technology by itself. The industry believes it essential to establish a mechanism to encourage the implementation of such technologies, whether through grants, the sale of carbon credits or any other analogous mechanisms.⁴⁴

Furthermore, alongside the introduction of CO₂ capture technologies, the sequestering of atmospheric CO₂ in forests and underground ought not to be neglected. As the representative of the BIOCAP Canada Foundation argued, it has been estimated that at least 30 million tonnes of CO₂ equivalents could be stored in this way by 2050.⁴⁵

The Committee therefore recommends that the Government of Canada continue to fund government, university and industrial research into important carbon sequestration measures such as improved forest management, agricultural and landfill practices, the use of algae, and the use of biomass as fuel.

In addition, the Committee strongly endorses the goal of the Pembina Institute that the oil sands should become carbon neutral by 2020 through the adoption of new technologies such as carbon capture and sequestration, and/or through the purchase of offsetting carbon credits. Furthermore, this Committee believes that being able to sell a “carbon neutral” barrel of oil will help the industry to maintain access to markets where there is concern about greenhouse gas emissions.

The Committee further recommends that the federal government introduce a regulatory framework that would place constraints requiring the industry to introduce technologies to drastically reduce greenhouse gas emissions, along with mechanisms such as emission credits trading, as incentives for financing these technologies.

Moreover, the Committee believes that any future expansion of oil sands development should be done in a way that it does not jeopardize Canada’s international Kyoto obligations on GHG emissions and climate change. We call upon the federal government, in keeping with an emissions reduction strategy for large final emitters, to introduce hard emissions caps for the oil sands for 2008 to 2012, 2020 and 2050, based on absolute levels and not based on “intensity.”

Not everyone shares the same vision about who should pay for the capture and storage of CO₂. Some argue that in view of the oil and gas industry’s record profits in 2005, and the capacity for innovation in terms of technology and performance, it has demonstrated in the past that it could cope with economic and environmental challenges, and therefore that the industry has no choice but to meet the challenge of CO₂ sequestration and storage. Many of the witnesses heard by the Committee also mentioned the accelerated capital cost allowance available to the oil sands industry.

4.    Fiscal Treatment of the Oil Sands

The Government of Canada does not directly subsidize oil sands activities. It does however assist the industry by providing tax incentives that encourage investment and development. The Committee heard convincing testimony that capital investments in oil sands mines and in situ oil sands projects are treated preferentially relative to the broader energy sector. In particular, oil sands investments benefit from the accelerated capital cost allowance, similar to mining operations.

The capital cost allowance (CCA) is a non-refundable tax deduction that reduces taxes owed by permitting the cost of business-related assets to be deducted from income over time. CCA rates are generally set to reflect the economic life of assets. Most capital assets used in the extraction and processing of conventional oil and gas can be deducted at a rate of 25% per year on a declining balance basis.⁴⁶

Oil sands investments, however, benefit from an accelerated capital cost allowance rate of 100%. In practice this means that no federal corporate income taxes are paid on the income that flows from new oil sands projects until all eligible capital costs associated with those projects are first written off for income tax purposes. It is important to recognize that accelerating the capital cost allowance for oil sands investments results in a deferral of taxes payable. It does not change the overall level of tax that is payable. The tax expenditure then is the cost to the federal government of having taxpayers claim deductions sooner rather than later. In others words, the tax expenditure is a function of the time value of money. But by allowing oil sands capital investments to be depreciated in this accelerated manner, the federal government is providing an important stimulus for investing in the oil sands and deferring tax revenue in a temporary manner.

The Committee therefore recommends that the government of Canada eliminate the accelerated capital cost allowance currently applicable to the oil sands industry in order to place it on an equal footing with the broader oil and gas industry.

5.  Use of Water

Fort McMurray and the Athabasca River are part of the vast watershed of the Mackenzie River, which covers an immense area of 1.8 million square kilometres, or one sixth of Canada’s surface area. However, the population is only 360,000. Unlike most of the major river basins of the world, where development and populations are found mainly downstream, close to the mouths of the rivers, the development of the Mackenzie basin is occurring upstream. The Wood Buffalo and Fort McMurray region is without a doubt the region undergoing the most intensive development in recent years.

Generally speaking, the use of water in the oil sands has become an issue because of the large quantities of water required to extract and process bitumen. And yet, the Pembina Institute was also keen to point out that oil sands mining—the most visible of the oil sands activities—which has a very strong impact on rivers and wetlands, first requires that wetlands be drained before removing the surface layers to expose the bitumen. Likewise, the bottom aquifer, which is the layer of water below the bitumen, must also be drained to avoid flooding the mines. This procedure can therefore lead to a considerable reduction in the amount of water and surface area of wetlands in the region.

Nevertheless, according to the Institute, the most water is used by the processes that extract bitumen from the sands and that produce synthetic crude oil. In fact, although bitumen only accounts for approximately 10 to 12% of the total quantity of mined material, two to four and a half barrels of water are nevertheless required, even with water recycling, to produce one barrel of synthetic crude.⁴⁷Most—two thirds in fact—of all water removed from the Athabasca River is for oil sands recovery; hence its enormous importance in supplying water to the industry. For example, it has been estimated that operations currently under way use as much water as the City of Calgary, which has a population of approximately one million.⁴⁸ If projects that are at the planning stage are added to the existing projects, then the amount of water used would be approximately the same as for the City of Toronto, and this is only for oil sands mining operations. Also according to the Pembina Institute, less than 10% of this water is returned to the Athabasca River and people are wondering whether there is enough water in the river to provide the flow required to keep the aquatic ecosystem healthy, particularly in view of the very low flow rate in winter which can vary significantly from one year to the next.

In view of the inability of the Cumulative Environmental Management Association (CEMA) to determine the flow requirements for the river prior to January 2006, the Alberta Department of the Environment had to establish a provisional framework for flow requirements and water management over the lower portion of the Athabasca River. The framework established a number of flow thresholds, potential environmental impacts and management requirements, but it has not yet been implemented. The most recent draft, dated July 10, 2006, to which Fisheries and Oceans Canada contributed, is considered inadequate by Aboriginal and environmental groups because the framework would still allow the removal of water from the Athabasca River, even when there is a serious risk involved. New water allocation decisions could well be taken even though no sound water management framework is yet in place.

Some are also worried by the impact of drainage from the Athabasca River into the Peace River and Athabasca River delta, the largest boreal delta in the world and one of the largest nesting and rest areas for waterfowl in North America. According to the Pembina Institute, “More research is needed to determine how the oil sands activities actually impact on the ecosystem and also on the aboriginal fishing in the delta.”⁴⁹

In addition to the removal of water from the Athabasca River, the issue of residual water remains a concern to a number of witnesses heard by the Committee. According to Dr. Mary Griffiths of the Pembina Institute, only a small percentage of the water taken from the Athabasca River would be returned to it, with most of the water diverted to tailings ponds. Some people argue that it is difficult to talk about tailings ponds because the tailings catchment area covers approximately 50 km² (5,000 hectares).⁵⁰The National Energy Board also considers tailings management a major challenge, because once the bitumen has been separated out, much of the water becomes contaminated with residual sand and bitumen as well as related contaminants. Specialists from the CANMET Energy Technology Centre in Devon have described the process as follows:

The problem is that while the sand in the waste stream settles rapidly when it’s dumped into the pond, the clay stays suspended, and over about three years it forms a thin sludge called mature fine tails, which is why they’re called tailings ponds. This is about the consistency of ketchup, and it doesn’t settle any further. The water in these ponds is much saltier than river water, and it is toxic, due to the presence of naphthenic acids, although this toxicity does disappear with time, as natural bacteria break down the naphthenic acid molecules, usually over one or two years.⁵¹

It is therefore essential that water from the tailings ponds does not get into the groundwater or the soil. The introduction of new technologies designed to reduce the volume of water used in bitumen extraction is therefore key. For about 15 years now, the CANMET Energy Technology Centre in Devon has done a great deal of research into tailings. For example, it made an active contribution to the “Fine Tails Fundamental Consortium”, a joint initiative over five years at $3.8 million per year, which resulted in a method for treating composite tailings that produce mud with a lower water content. Experiments on consolidated tailings did succeed in the reclamation of approximately ten hectares on which a few plants are growing, but could not guarantee the rehabilitation of the boreal forest and natural peat bogs that were there prior to development. As to the use of bitumen extraction processes that produce composite tailings or dry tailings, Mary Griffiths of the Pembina Institute noted that it may take until the year 2030 before any breakthroughs are made or any alternatives to bitumen extraction using water.⁵²

The issues are somewhat different for in situ oil sands operations. Although these at the moment account for only a third of bitumen production in Alberta, these methods will certainly increase gradually in the longer term because a high percentage of bitumen is located too deep for mining. According to NEB baseline forecasts, net volumes of bitumen produced by open pit mining, in situ thermal separation and in situ non-thermal primary recovery will respectively account for 52%, 44% and 4% of production by 2015.⁵³In situ production uses a great deal of water to produce the steam that is injected into the bitumen to heat it and soften it so that it can be pumped to the surface. However, the water used for this purpose comes mainly from underground saline phreatic water and soft groundwater at low depth. The problem is that knowledge of the aquifers is still very still fragmentary, not only in Canada but in Alberta as well—with the possible exception of the Paskapoo aquifer, which is what has led the Pembina Institute to say that we do not have enough baseline data to be able to determine the impact of in situ operations on groundwater. In view of the significant drainage that would be required for wetlands prior to mining, and potential climate changes, there are serious concerns about the rate at which shallow soft water aquifer levels can be restored. The Geological Survey of Canada, which falls under the Department of Natural Resources, has conducted in-depth research and done detailed mapping of the whole Northern Alberta area in order to acquire a better understanding of what is happening with aquifers and groundwater. However, it is the provinces’ responsibility to supervise and monitor groundwater.

The Committee therefore recommends that Natural Resources Canada, through the Geological Survey of Canada, and working together with the province, ramp up and accelerate work on research into aquifers in Alberta, particularly in the current and potential oil sands operations areas.

Pilot projects to reduce the use of water have attempted to use a mixture of solvents and steam. The “toe to heel air injection” (THAI) process that burns the bitumen in situ to heat it up, and then uses the heat from the residual burn to heat up adjacent bitumen, which melts. However, it is still too early to establish whether these techniques can be used.

The water recycling rates from oil sands extraction and treatment processes varies from 50 to 80% in mining operations and can reach as high as 90% and over in in situ recovery when the water is treated to make dry saline waste and cleaner water for steam generation.⁵⁴ The industry has certainly made significant progress in reducing its use of water. For example, Suncor has doubled production over the past five years without increasing its water consumption.⁵⁵ Similarly, Syncrude has reduced its water consumption by 60% since the early 1980s through, for example, the on-going implementation of better ways of recycling, monitoring, maintaining and retrofitting equipment. Syncrude now imports 2.3 cubic metres of water from the Athabasca River per cubic metre of crude oil produced, which is less than half of the industry average and the lowest water intake rate in the oil sands industry. At Syncrude’s operations, every cubic metre of imported water is recycled 18 times.⁵⁶As explained during the Committee’s visit of Syncrude facilities in November 2006, such achievements in water recycling are possible since the company has had years to fill out its retention ponds from which it then takes used water for certain processes. New projects rely to a greater degree on water taken from the Athabasca River, at least until sufficient quantities of water have accumulated in associated retention ponds and can then be recycled.

Real progress has been made by the industry, but in view of the pace of development being considered, the Athabasca River basin could encounter serious problems unless there is a radical change in technology in terms of water use. One promising example of a technology that uses virtually no water and less energy is the THAI process, mentioned by Dr. Michael Raymont. It uses underground combustion that is initially started by combustion gas and then carried along by air injection to improve the viscosity of the oil sands and make it possible to collect the bitumen through an underground pipe before pumping it to the surface.⁵⁷

The evidence heard by the Committee clearly shows that the water issue remains crucial at several levels when it comes to developing the oil sands. The Committee is concerned about the impact of current and projected oil sands activity on water systems of the Athabasca River basin. It believes that it is imperative to reduce water consumption, and to deal with the processing of toxic wastewater in order to re‑use it in industrial processes before returning it to the river. These are enormous challenges to the industry and to researchers.

Therefore, the Committee recommends that the federal government work together with its partners in the Governments of Alberta, Saskatchewan and the Northwest Territories, universities and industry to step up research in order to:

•       determine the true impact of oil sands activity on the Athabasca River ecosystem, as well as on Aboriginal fisheries in the Peace and Athabasca river delta;

•       acelerate the treatment of toxic wastewater that has accumulated in the retention ponds so that these waters can be re-used in industrial processes and ultimately returned to the river; and,

•       accelerate the introduction of technologies that will radically reduce the use of water in bitumen extraction and treatment processes.

6.  Land Reclamation

The very nature of oil sands means that developing them, whether by mining or the in situ method, causes incredible disruption to land and landscape over immense areas. For oil sands mining, the forest needs to be cleared and the covering layer of earth removed before the sands can be excavated. Estimates show that the disturbed area could be as extensive as 3,000 km². For in situ operations, landscape degradation may appear less severe, but the need to dig several wells and to build roads, pipelines and transmission lines requires the clearing of a considerable portion of the boreal forest. The impact on the landscape may seem to be less drastic, but the most serious impact is the fragmentation of habitat for both flora and fauna. This form of development could affect tens of thousands of square kilometres of boreal forest over the long term.⁵⁸

Therefore, the Committee recommends that the federal government, in partnership with the provincial government, assess the impact of all oil sands development projects on the boreal forest, and that it consider the introduction of compensatory conservation methods for the creation of protected areas in the region surrounding the oil sands, as well as in the broader region of the Mackenzie River watershed.

Under Alberta legislation, oil sands developers, in order to obtain the required permits, need to conduct an environmental impact study of their project and submit a detailed land reclamation plan to be implemented once the extraction of bitumen has been completed. Generally speaking, land reclamation means returning the layer of arable land after setting it aside prior to operations—and revegetating with trees, shrubs and other plants indigenous to the region. The process takes many years. Companies that conduct oil sands mining operations are also required to pay a performance bond equivalent to the cost of future land reclamation work.

Suncor and Syncrude have been pioneers in land reclamation, with Suncor beginning its reclamation activities in the 1960s. It is nevertheless a slow and long-term process because of the challenges involved. Fewer than 1,000 hectares of land have been rehabilitated by Suncor, and 4,500 hectares by Syncrude, which anticipates that work will have to be spread over 50 years to meet government requirements. A company official testified that Syncrude has made steady progress in recent years:

To summarize, at the Syncrude Mildred Lake site we are already reclaiming land more rapidly than we’re disturbing land. We are drawing down the footprint of that site. At the pace we’re currently reclaiming land, 260 hectares, about one square mile last year, we have about 50 years of work ahead of us. We have about 30 years of mining at that site, and after mining is finished, the reclamation has to be completed, perhaps another five or ten years’ work. So it’s a 35 or 40-year project. Working at the current pace, we’d get it done in 50 years. We really should pick up the pace a bit, but only a bit. We’re pretty well where we ought to be.⁵⁹

For the time being, no certification from the Government of Alberta has been requested or granted for land reclamation; once certified, these lands would become public property once again. The Government of Alberta estimates that approximately 42,000 hectares of land have thus far been altered by oil sands mining.

Despite all the efforts and money spent by the industry in the field and on research, not everyone shares its optimism. Some feel that there has not yet been sufficiently large-scale reclamation to demonstrate that it is possible to restore diversified boreal ecosystems. There are also fears that once the groundwater and surface water circulates in rehabilitated areas where solidified residues have been incorporated into the landscape, there will be a risk of various toxic substances being released. There are therefore questions about the repercussions with respect to the long-term ecological viability of these sites after they are considered to have been rehabilitated. Fears have also been expressed about mature fine tails, because we do not yet know enough about how they can be effectively managed over the long term. At the moment, these sludges, which contain residual toxins, sink to the bottom of what is called kettle lakes, the water in which could flow into the Athabasca River. Some observers feel that oil sands are being developed over vast land areas without any demonstration of the effectiveness of reclamation methods.⁶⁰

While acknowledging the major commitment made by the CANMET Devon Centre to research reclamation issues, the Committee believes it is incumbent upon the industry itself to take the lead and to accelerate research and action in land reclamation, particularly with respect to the potential toxicity of tailings and water.

Social issues

Oil sands development produced unprecedented economic growth in the vast Fort McMurray region. There was no way to have predicted such rapid growth in development projects since the end of the 1990s. In 1995, it was estimated that the very ambitious production target of a million barrels a day would be reached around 2020; it was in fact reached in 2004, 16 years ahead of schedule. While such a production level has a major economic impact on the region and Canada as a whole, it has also created equally significant upheavals on a municipal and social level. What is more, oil sands development is occurring in a region with a major Aboriginal presence.

1.  Impact of oil sands activities on First Nations

The development of the oil sands has brought about an unprecedented economic boom to the Wood Buffalo region of Alberta. First Nations have been able to carve out some benefits from this economic activity. For example there are now employment and business opportunities for Aboriginal peoples where none existed previously. Some companies, such as Syncrude, are making a concerted effort to reach out to Aboriginal peoples and support their involvement in the oil sands industry. In 2005, the industry spent $310 million in contracts to source goods and services within aboriginal businesses.

Unfortunately, the economic benefits that flow from the oil sands are not evenly distributed, and many residents of First Nations communities continue to live in poverty in spite of the region’s tremendous wealth. The Committee heard poignant testimony to that effect from Pat Marcel, chair of the Athabasca Chipewyan First Nation elder’s Committee. Mr. Marcel pointedly explained to the Committee that poverty persists in the Wood Buffalo region despite the billions in investments and rising oil revenues:

“[N]ear Canada’s Athabasca oil sands, where purchases are measured in the billions and the average annual salary is approaching six figures, there is a group of people living as if they live not in Canada, but in a third-world country. To be clear, our elders are struggling to put food on the table while industry is getting their approvals and government is getting billions in royalties from our traditional lands.”⁶¹

Mr. Marcel stated that the oil sands activities are also jeopardizing the traditional ways of the region’s Aboriginal inhabitants and possibly endangering their health. Oil sands mining and in situ projects are taking up ever larger portions of First Nations’ traditional territories and disrupting the landscape and ecosystem from which First Nations traditionally sustain themselves. There is also evidence that the Wood Buffalo region is increasingly polluted, such that the Aboriginal inhabitants “are afraid to eat the traditional foods that have sustained us for thousands of years.”⁶²

While Aboriginal peoples in the Wood Buffalo region are deriving some economic benefits from oil sands activities, it is not clear whether such benefits compensate for the long-term social and environmental impacts of this very rapid industrialization. The Committee heard Mr. Marcel’s plea “not to forget the people whose land it is they’re getting the tar sands from and all the development there. They’re my traditional lands.”⁶³

This Committee endorses the plea of Pat Marcel not to forget the aboriginal peoples in the Wood Buffalo region whose traditional lands are impacted by oil sands development. The Committee strongly encourages industry and government to continue and expand consultations with residents, both aboriginal and non‑aboriginal, whose communities are affected by these developments. Further, the Committee recommends that the federal government take necessary measures to improve living conditions for the aboriginal communities whose way of life has been impacted by extensive oil production on their traditional lands.

2.  Social impact of oil sands activities

Just like the economic and environmental considerations, the local and social aspects also pose problems and enormous challenges for the communities at the heart of oil sands development. In addition to the labour availability issues raised earlier, there are equally important issues of the local infrastructure and social services that are often related intrinsically to other facets of the region’s frenetic development. The Committee heard a great deal of evidence that provides perspective on the extent of the problems encountered in the Regional Municipality of Wood Buffalo.

The Regional Municipality of Wood Buffalo, which includes the town of Fort McMurray, has a population of over 80,000—not counting a shadow population estimated to be between 10,000 and 12,000—while the municipal development plan assumes a population of 52,000 in Fort McMurray. If the rate of growth continues for the next six years, a conservative estimate, it would mean that the population of Fort McMurray could almost double by 2012. The projects in recent years and those approved for the next few years thus exceed all the forecasts made in the municipality’s plans, as was made clear by the Mayor of the Regional Municipality of Wood Buffalo:

[…] we’re spending $160 million for a new waste water treatment plant that’s going to open with an immediate need for expansion, and we’re currently exceeding our production capacity. We have $40 million for an expansion to the water treatment plant, which will reach capacity next year; $107 million for a MacDonald Island recreation centre redevelopment; $24 million for new landfill; and $51 million for a new RCMP facility, and that budget, in fact, started at $30 million for two facilities, not just one.⁶⁴

In addition, rental costs are the highest in Canada and real-estate costs are the highest in Alberta. It currently costs around $485,000 for an average single-family home in the Fort McMurray region. The supply of new houses is considerably delayed by the lack of land and the shortage of construction workers. The regional municipality is experiencing traffic jams worthy of one of the country’s major cities because of the lack of either public or private transportation infrastructures adapted to the new needs created by the rapid increase in activities.

Mayor Blake stated that, on a social level, the health-care system requires a 100% increase in the number of resident doctors, a new funding formula, a new continuous care facility and 150 additional staff members. The municipality needs more schools, more teachers and more educational resources, while the social programs, services and facilities do not meet current needs for daycare, substance abuse, domestic violence and homelessness services.

According to the NEB, $1.2 billion in capital spending will be needed over the next five years to meet all of the region’s public infrastructure needs.⁶⁵ The Mayor of the Regional Municipality of Wood Buffalo says that the municipality’s capacity to respond to the basic infrastructure needs is stretched beyond its limits given the current pace of oil sands development. Without additional assistance, this simple reality threatens the sustainability of oil sands development. The problems and challenges are so great that the Council of the Regional Municipality of Wood Buffalo is now considering a delay in, but not a moratorium on, some oil sands development projects until adequate mechanisms can be established to ensure responsible development that benefits the people of Wood Buffalo, Alberta and Canada.⁶⁶

The Committee was able to see the extent to which the accelerated development of the oil sands has had an impact on the Wood Buffalo region and how urgent it is to find adequate, concerted responses to the local and social problems created by the region’s excessively quick growth. If it deems it advisable, the Government of Alberta can work with the federal government and the Regional Municipality of Wood Buffalo to explore the best means available to them to improve the urban and social infrastructures that will be required in the long term to ensure the development of the oil sands and the well-being of the local populations.