Appendices
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(Updated 26 May 2010)
Canada generated 631 billion kWh in 2007, of which about 14.7% was from nuclear generation, compared with 58% from hydro, 17% from coal and 6% from gas. Annual electricity use is approaching 16,000 kWh per person, one of the highest levels in the world.
According to a study by the Canadian Energy Research Institute,1 in 2005 Canada’s 18 nuclear reactors sold energy worth almost C$5billion, contributed C$6.3 billion to GDP, and created C$1.4 billion in government revenue. The nuclear power industry employed, directly and indirectly, over 66,000 people.
About C$13.26 billion (in 2005 dollars) was invested by the government in Canada's nuclear program over 1952-2006 through AECL. This investment has generated more than C$160 billion in GDP benefits to Canada from power production, research and development, CANDU exports, uranium, medical radioisotopes and professional services, according to AECL.
Reactor development
Canada has developed its own line of nuclear power reactors, starting from research in 1944 when an engineering design team was brought together in Montreal, Quebec, to develop a heavy water moderated nuclear reactor. The National Research Experimental Reactor (NRX) began operation in 1947 at Chalk River, Ontario, where today the Chalk River Laboratories are the locus of much of Canada's nuclear research and development. The government established Atomic Energy of Canada Ltd (AECL) in 1952 with a mandate to research and develop peaceful uses of nuclear energy. The National Research Universal (NRU) reactor was built at Chalk River in 1957. Today, NRU produces most of the world supply of molybdenum-99, the source of technetium-99 widely used for medical diagnosis, and cobalt-60 for cancer treatment.
AECL, in cooperation with Canadian industry, began developing the first CANDU (Canada deuterium uranium) reactor in the late 1950s. CANDU reactors use heavy water (deuterium oxide) as a moderator and coolant, and are fueled using natural uranium (as opposed to enriched uranium). The advantages of the CANDU reactor are savings in fuel cost, because the uranium does not have to go through the enrichment process, and reduced reactor downtime from refueling and maintenance. These savings are partially offset by the cost of producing heavy water. A small (22 MWe) CANDU prototype went into operation in 1962 at Rolphton, Ontario, 30 km upstream from the Chalk River facilities. A larger prototype – 200 MWe – began generating power at Douglas Point, Ontario, in 1967. It was the design basis of the first Indian PHWR power reactors, Rawatbhata 1 & 2.
The first commercial CANDU reactors began operations in Pickering, Ontario, in 1971. Sixteen of Canada's 18 commercial reactors are located in Ontario (the others are in Quebec and New Brunswick). In 2008, 53% of Ontario's electricity production came from nuclear power. The Darlington plant which came on line 1990-93 experienced a major cost overrun in construction largely due to political interference.
The technology and design of CANDU reactors have evolved through several generations, with the newest reactors the Enhanced CANDU 6 (based on Qinshan in China), and the next generation the Advanced CANDU Reactor (ACR-1000).
Today, there are 29 CANDU reactors in seven countries, as well as 13 'CANDU derivative' reactors in India, with more being built. Export sales of 12 CANDU units have been made to South Korea (4), Romania (2), India (2), Pakistan (1), Argentina (1) and China (2), along with the engineering expertise to build and operate them.
Canada's nuclear power reactorsa
Reactor refurbishment
To meet current and future electricity needs, provincial governments and power companies have made the decision to extend the operating life of a number of reactors by refurbishing them. Refurbishing CANDU units consists of such steps as replacing fuel channels and steam generators and upgrading ancillary systems to current standards. While refurbishing usually takes less time and is less costly than building a new plant, there have been several cost overruns that in some cases have made it almost as expensive as new construction.
Full refurbishment of the later model Candu 6 units such as Point Lepreau involves much more: replacement of all calandria tubes, steam generators and instrument and control systems. (This first project has gone over time and budget, but the second, at Wolsong 1 in Korea, is benefiting from the experience. The third will be Gentilly 2, then Embalse in Brazil.)
Pickering
Pickering A1 and A4 have both been refurbished in recent years, extending their life expectancy to 2022 and 2018, respectively. The Pickering 1 refurbishment in 2004-05 cost its operator Ontario Power Generation (OPG) over US$1600/kWe, more than double the original estimate, which led the government to retire units 2 & 3 rather than refurbish them.
The Pickering B reactors are licensed to mid-2013. In February 2010, OPG decided against full refurbishment, but will spend C$ 300 million on keeping them going for another ten years before finally closing and decommissioning them.
Bruce
Facing an impending power shortage, the Ontario government in October 2005 agreed with Bruce Power to refurbish its four oldest reactors, collectively known as Bruce A, each with 769 MWe capacity (see Appendix 1: Ontario Energy Policy). Refurbishment is underway at units 1 and 2. Unit 2 was earlier laid up in 1995 due to a maintenance accident in which lead contaminated the core. Unit 1 was laid up along with the four Pickering A units at the end of 1997, and the other two Bruce A units early in 1998, to allow operational focus on newer plants. Both units 1 & 2 are scheduled to restart in 2010, with their operational lifetimes extended another 25 years. Bruce A units 3 and 4 were returned to service in January 2004 and October 2003, respectively. Refurbishment of these two units is planned to commence in 2010.
UK-based AMEC is managing Bruce A work. The whole Bruce A project was expected to cost C$5.25 billion, with C$2.75 billion for units 1 and 2, C$1.15 billion for unit 3 and $1.35 billion for unit 4. Early in 2008, with C$2 billion spent, it was announced that the cost of unit 1 & 2 refurbishment would be about C$3 billion, which was later increased to C$3.1-3.4 billion. In November 2009, both units were given regulatory approval for restart, though unit 2 is not expected back on line until mid-2011, and unit 1 late in 2011.
Bruce Power will be paid for all electricity from Bruce A on the basis of a 6.3 cents/kWh current reference price capped for 25 years (cf 6.765 ¢/kWh average Ontario spot price in 2005, and 4.5 ¢/kWh floor price for Bruce B – units 5-8). If the capital expenditure is over or under the $4.25 billion (apart from unit 4 refurbishment), the difference will be shared between the government and the investors. One of the partners in Bruce Power, Cameco (31.6%), said that while it strongly applauded the project it did not meet Cameco's investment criteria, so it received a $200 million payout of its interest in Bruce A. The other partners have set up Bruce A Limited Partnership (BALP) to sublease Bruce A from Bruce Power and to pay for the project.
Decisions on the four Bruce B reactors are pending, though in July 2009 Bruce Power announced that it would focus on refurbishing these rather than building new plants at Bruce. Early in 2010 the company completed work to uprate the four units from 90% to 93% of original design capacity by modifying the fuel loading.
Darlington
These are Canada's newest CANDU reactors and currently licensed to 2020-23. Following detailed studies, OPG decided on full refurbishment starting about 2016 and consequent 30-year life extension. Detailed planning for this will include an environmental assessment, an integrated safety review and an integrated improvement plan that will define the scope, cost and schedule of the refurbishment project. Replacing fuel channels and steam generators and upgrading ancillary systems to current standards are likely. (The Darlington site has been selected by the Ontario government as the location for the province's next nuclear generating facility, of up to 4800 MWe, but this plan is on hold – see section on Ontario under New Reactors below.)
Point Lepreau 1
In mid-2005, the decision was made to refurbish New Brunswick Power's 635 MWe Point Lepreau reactor, which provides one quarter of the province's power. It was the first CANDU-6 type in commercial operation and is the first CANDU-6 reactor to undergo full refurbishment, including replacement of all calandria tubes as well as steam generators. Work began in April 2008 and the reactor is expected to be back in service in February 2011, extending the life of the reactor to 2034 or beyond, and providing a 25 MWe uprate. Originally estimated to cost C$1.4 billion including replacement power, the project has been running well over budget. There was a proposal to sell the unit for C$ 1.4 billion to Hydro Quebec, to be finalized after the reactor was back on line, but this was cancelled in March 2010.
Gentilly 2
Hydro Quebec decided in August 2008 to refurbish the 638 MWe Gentilly 2 as an alternative to closing it in 2011. Most Quebec electricity is hydro, from the north of the province. Gentilly, close to the load centre, has particular importance for grid stability and it also provides energy security regardless of seasonal rainfall. The C$1.9 billion investment includes construction of a radioactive waste management facility. The work is planned to be carried out in 2011-12.
New reactors
There are proposals to build several nuclear reactors to go into operation in the next decade. Four reactors are planned in Ontario, one is proposed in New Brunswick and one (or possibly four smaller reactors) in Alberta. Total capacity of the new reactors may amount to as much as 9 GWe.
Planned or proposed Canadian nuclear power reactorsc
Ontario
In June 2006, the Ontario government implemented a 20-year Energy Plan, which envisages maintaining existing nuclear generation capacity at 14,000 MWe (see Appendix 1: Ontario Energy Policy). A commercial team directed by Infrastructure Ontario is managing the procurement process to select a nuclear reactor vendor.
In August 2006, Bruce Power applied for a licence to prepare its 9.3 km2 Bruce site for construction of up to four new reactors. The Canadian Nuclear Safety Commission (CNSC) accepted the company's project description for 4,000 MWe in January 2007. In order to expedite environmental assessment, the Commission recommended that the project go straight to a public review panel rather than negotiating an eight-month process to determine if such a panel was necessary. Bruce Power submitted an environmental impact statement in September 2008, showing that up to four new reactors at Bruce C would have no significant environmental effect. The new units were envisaged as coming on line beginning in 2015. Six different reactor types were under consideration. However, in July 2009 the company announced that it would withdraw its site license application and suspend its Environmental Assessment for Bruce C, and focus on refurbishment of Bruce A and B.
In September 2006, Ontario Power Generation (OPG) applied for a licence to prepare its Darlington site for construction of up to four new nuclear power units. The application is being reviewed by the CNSC and could lead to a Licence to Prepare Site being issued by the end of 2010.
In March 2008, Ontario's Minister of Energy invited companies to submit proposals to build two new nuclear reactors at Darlington or Bruce, or both. In June 2008, the Ontario government selected Darlington as the site for the two new nuclear reactors, to be operated by OPG and to come on line in 2018. Three submissions were received by the February 2009 deadline – from Areva (US EPR), Westinghouse (AP1000) and AECL (ACR-1000). However, in June 2009 the provincial government announced that the project was being stalled pending resolution of the future of AECL. Two other bids were non-compliant in accepting price escalation risk.
When the government selected Darlington for new nuclear capacity, it affirmed the importance of privately-run Bruce Power and the need for it to contribute 6,300 MWe of nuclear capacity, and maintaining this level of capacity beyond the present planned operating lifetime of Bruce B. A decision on refurbishing Bruce B (3,260 MWe) is pending but highly probable, now that the alternative proposal to build four new reactors there as Bruce C has been shelved.
In October 2008, Bruce Power announced it would conduct an environmental assessment for two new nuclear units in the Haldimand-Norfolk region of southern Ontario. The region is home to OPG's 4,096 MWe Nanticoke Generating Station, the largest coal-fired power plant in North America. The Nanticoke plant had been scheduled for closure under the provincial government's plan to phase out coal power, but after several delays, the planned closure date is now in 2014. Although both the Haldimand and Norfolk councils supported the Bruce Power proposal, as well as 80% of residents according to an Ipsos-Reid poll, the Ontario government has not supported it. In July 2009, Bruce Power withdraw its site licence application and suspended its environmental assessment.2
New Brunswick
In 2007, the New Brunswick provincial government requested a feasibility study on building a second reactor at the Point Lepreau site, possibly a 1085 MWe ACR-1000 unit with a life of 60 years. If approved, it would be the first ACR-1000 plant in Canada. The study is being conducted by the Team Candu consortium of AECL, GE Canada, Hitachi Canada, Babcock & Wilcox Canada and SNC-Lavalin Nuclear. Team Candu was set up in 2006 to offer fixed price plants on a turnkey basis. While government-owned NB Power would be licensee and operator, the plant would most likely be privately owned and financed rather than publicly financed from government debt. About half of the output is likely to go to the northeastern USA. There is over 1300MW interconnection to New England, and in 2007 it imported 12 TWh from New Brunswick.
Proposals have also been made for a third reactor in New Brunswick, mainly for the purpose of exporting power to New England.
Alberta
Much of the interest in building nuclear reactors in Alberta centers on the extraction of oil from the province's extensive oilsands (tar sands) deposits. The current extraction process relies on energy from natural gas, which is costly and poses the additional problem of carbon emissions. Nuclear power is considered an economically attractive, low emission alternative for producing the steam and electricity the oil extraction process requires. (See Appendix 2: Alberta Tar Sands)
The current Alberta proposal by Bruce Power Alberta is for up to 4,000 MWe of nuclear capacity at the Whitemud site approximately 30 km north of Peace River, 500 km northwest of Edmonton, costing up to $10 billion. The main discussion has centred upon building twin ACR-1000 reactors primarily for electricity rather than steam production, although the technology choice remains open. Most of the power would be supplied to the grid, but off-peak it would be used for hydrogen production (for oil refining). In November 2007, Bruce Power took over a previous application by Energy Alberta, and is proceeding with a full environmental study. Bruce Power is 31.6% owned by Cameco. Another Bruce partner, TransCanada, has expressed interest in building nuclear power capacity in Alberta.
Alberta's nuclear consultation process in 2009 confirmed that the technology could play a role in the province's future energy mix – the Government said nuclear power will be given the same consideration as all other energy options.
Saskatchewan
At the end of November 2008, a joint feasibility study by Bruce Power and SaskPower concluded that nuclear power could contribute at least 1,000 MWe capacity to Saskatchewan’s generation mix by 2020. The study identified a region spanning from Lloydminster, including the Battlefords and Prince Albert – generally referred to as the 'Prince Albert economic sub-region' – as the most viable host for a nuclear facility. The study also noted that growth in electricity demand in northeastern Alberta could provide a possible export market for Saskatchewan.3 SaskPower currently operates 3065 MWe of capacity, more than half of it coal-fired. The company has previously investigated the prospect of nuclear power and in 2007 suggested that a 360-750 MWe reactor size would be feasible if Alberta is included, or larger if it also included Manitoba.
In March 2009, the major Uranium Development Partnership report from a widely representative government-appointed panel recommended that Saskatchewan should move towards building nuclear power capacity.4 The report recommended maintaining a focus on uranium mining and exploration, since the province provides all of Canada's current uranium production. It specifically discouraged value adding in conversion and fuel fabrication, but said that up to 3,000 MWe of nuclear power capacity would be appropriate for the province, with major net economic benefit. Overall the panel said that its recommendations could increase the province's gross domestic product by an estimated C$50 billion and create 6,500 construction jobs and 5,500 long-term jobs. It also suggested working with Alberta to consider "a common power-generation solution for the two provinces by pooling their power needs." Subsidiary recommendations included building a research reactor and pursuing medical isotope production in partnership with the federal government, and getting involved with laser enrichment technology (Saskatoon-based Cameco has 24% of the main developer already).
A public consultation on the report then resulted the government supporting most of the recommendations but saying that it would not support Bruce Power's proposal or any immediate "addition of 1000 MWe as proposed from a single nuclear reactor", but SaskPower should keep the option open for the long term.5 However, the Energy and Resources Minister noted that "the large scale of the proposed nuclear power investment requires a regional approach involving, ideally, all three prairie-provinces for successful implementation," which is in line with the UDP recommendation.
New reactor designs
Since its inception in the late 1950s, the CANDU reactor design has gone through several generations of evolution to improve fuel efficiency and flexibility, meet more stringent safety requirements and reduce costs and construction time.
Innovation has continued on the current CANDU 6 design. Although it was later shelved, features from the CANDU 9 design (about 900 MWe) have been incorporated into recent CANDU 6 reactors. The CANDU 9 design has flexible fuel requirements ranging from natural uranium through slightly-enriched uranium, recovered uranium from reprocessing spent PWR fuel, mixed uranium and plutonium oxide (MOX) fuel, direct use of spent PWR fuel, to thorium. The innovations in CANDU 9, along with experience in building recent Korean and Chinese units, has gone into the Enhanced CANDU – built as twin units – with a capacity increase to 750 MWe and flexible fuel options, plus 4.5-year construction and 60-year plant life (with mid-life pressure tube replacement). Beyond this, the actual CANDU 9 design has been shelved.
The Advanced CANDU Reactor (ACR) represents a further evolution in design. While retaining the low-pressure heavy water moderator, it incorporates some features of the pressurised water reactor. Adopting light water cooling and a more compact core reduces capital cost. It will run on slightly enriched uranium (about 1.5% U-235) with high burn-up, extending the fuel life by about three times and reducing high-level waste volumes accordingly. Attention is now focused on the 1200 MWe ACR-1000. The modular construction means that major components can be built in US shipyards, using a high degree of standardisation of components. The ACR is designed to be built in pairs, and construction time is estimated at 44 months for the first unit and 36 months for the fifth and subsequent units. The Canadian Nuclear Safety Commission (CNSC) gave pre-project design approval to the ACR-1000 in February and September 2009, saying that it meets the overall regulatory requirements and the expectations for new nuclear power plants in Canada and that there are no fundamental barriers to licensing it. Phase 3 follow-up is die to be completed in mid-2010.
The Enhanced CANDU-6 is also undergoing CNSC review, with the first phase, initial design approval, granted in March 2010. The second phase of certification, intended to identify in greater detail any potential barriers to licensing the design, will run to 2012.
There were two main competitors with the ACR for new nuclear plants in Canada. The CNSC completed the preliminary design review of the Westinghouse AP1000 in February 2010, but Areva's EPR was put on hold by the vendor after its bid for Darlington was rejected in mid-2009.
Beyond the ACR designs, AECL is also developing the CANDU-X, a supercritical reactor that is a step forward from the ACR. It is expected to be available about 2020.
Research and development
Canada is a longtime leader in nuclear energy research and development. The Chalk River Laboratories in Ontario were set up by the government in the 1940s and have been the locus of much the world's successful R&D into the peaceful uses of nuclear energy. The 42 MWth National Research Experimental (NRX) reactor was built there in 1947, followed in 1957 by the 135 MWth National Research Universal (NRU) reactor, a world leader in the development and production of nuclear medical isotopes.
In 1952, the federal government established Atomic Energy of Canada Ltd (AECL) with the responsibility for managing Canada's national nuclear R&D programme, including NRU. AECL has undertaken all the developmental work on the Candu reactor types. It is now developing the third-generation Advanced Candu Reactor (ACR) and also has the lead role internationally in developing the Generation IV supercritical water-cooled reactor (SCWR – see page on Generation IV Nuclear Reactors).
Six other research reactors were built and continue to operate on university campuses. Five of these are SLOWPOKE-2 units, low-energy pool-type reactors designed by AECL with passive cooling and safety systems.
Two 10 MWth MAPLE (Multipurpose Applied Physics Lattice Experiment) at Chalk River Laboratories were to replace most of the radioisotope production at the ageing NRU reactor. Intended to be the world's first reactors dedicated exclusively to medical isotope production, the reactors could have supplied the entire global demand for molybdenum-99, iodine-131, iodine-125 and xenon-133. The reactors were originally scheduled to start up in 2000. One unit went critical in 2000, the second in 2003, but commissioning encountered major technical problems and in May 2008 AECL decided to cancel the project after spending $680 million on them. 6, d
The delay and eventual cancellation of the MAPLE reactors has led to the extended operation of the NRU research reactor. In December 2007, the Canadian Nuclear Safety Commission (CNSC) declined to allow the restart of NRU. A five-year licence renewal in mid 2006 had specified certain back-up modifications, which AECL had not fully implemented. Parliament then intervened and passed a bill authorising the restart. The government later made it clear that it was dissatisfied with both parties to the dispute, and the Chairman of AECL then resigned. The head of CNSC was relieved of her role soon afterwards, creating widespread concern about political interference in regulatory function. The modifications were completed early in February 2008.7
In May 2009, NRU was shut down again due to leakage of heavy water through corrosion. Repairing this is a major undertaking costing some $70 million, and the reactor is not expected back on line until early in 2010. Since it produces about 40% of the world's Mo-99 (for Tc-99m) this has a significant impact on supply of radioisotopes. AECL then hopes to run it until 2016.
While the MAPLE reactors were intended to take over medical isotope production from NRU, the neutron scattering research and CANDU materials testing activities of NRU were planned to be replaced by the Canadian Neutron Facility (CNF). A few years ago, AECL saw the CNF as essential to both CANDU R&D and materials science research, but little has been heard of it since about 2003.
In mid-2009 the Saskatchewan government proposed to the federal government that it should build a new 20 MWt research reactor – the Canadian Neutron Source – at the University of Saskatchewan. This would cost some C$ 500-750 million depending on how it was equipped, and the federal government was asked for 75% of this, plus 60% of operating costs. It would be optimized for Mo-99 production, mainly for export, to take over from NRU. The submission drew heavily on Australian experience with its Opal reactor, built by Invap of Argentina. There is already a Slowpoke-II research reactor on the campus, operated by the Saskatchewan Research Council, and a synchrotron.
Waste storage and disposal
Canada's Nuclear Waste Management Organization (NWMO) was set up under the 2002 Nuclear Fuel Waste Act by the nuclear utilities operating in conjunction with AECL. Its mandate is to explore options for storage and disposal, to then make proposals to the government and to implement what is decided. NWMO, working with AECL, is also required to maintain trust funds for used fuel management and probable disposal. Less than 3000 tonnes of spent fuel per year from Candu reactors is involved.
High-level waste
For high-level wastes, in 2005 NWMO published three conceptual designs for the technical options specified in the Nuclear Fuel Waste Act, based on proven technologies. The first, reactor site extended storage (at seven sites), was found to be feasible, requiring only some further dry storage facilities to be built. The second, centralised extended storage, is similar to systems already operating in 12 countries, but is longer term. Dry storage is also preferred in this case, with two options on the surface and two below ground level. A deep geological repository is the third possibility, allowing later retrieval if required. It is most closely aligned with international consensus and had already been the subject of detailed scrutiny by the federal Environment Assessment Panel over three years in the 1990s, involving public hearings. This option, known as adaptive phased management, was the one recommended by NWMO and chosen by the government in June 2007. NWMO is now responsible for implementing it.
A deep geological depository involves burying nuclear waste 500 to 1000 metres deep in the stable rock of the Canadian Shield, the large formation that extends northward across central and eastern Canada. The waste would be placed below the water table in containers packed in bentonite clay. The waste may consist of used fuel bundles or solidified high-level waste from reprocessing, sealed in copper or titanium containers.
Early in 2007, NWMO stated that a final repository would probably be in Ontario, Quebec, New Brunswick or Saskatchewan, and host localities would need to volunteer for the role. The organisation expects to have designed a siting process by the end of 2009 and to commence technical and socio-economic assessment of potential candidate sites by the end of 2012.8
Low- and intermediate-level waste
The nuclear utilities and AECL remain responsible for low- and intermediate-level wastes, which are currently stored above ground.
Following a strong positive response to polling of local residents, Ontario Power Generation (OPG) in 2005 proceeded with plans to construct a Deep Geologic Repository for its low- and intermediate-level wastes. The repository will be located 660 metres beneath OPG's Western Waste Management Facility, which it has operated since 1974. Environmental assessment and licensing is expected to take 6-8 years, culminating in a construction licence in 2012. Operation is expected in around 2017/18.
OPG is the owner and licensee of the repository; however, NWMO was contracted to manage development of it from the beginning of 2009.
The Western Waste Management Facility stores all the low- and intermediate-level nuclear waste from the operation of OPG's 20 nuclear reactors, including those leased to Bruce Power.
Legacy wastes
In June 2006 the Canadian government announced a five-year, C$520 million programme to clean up legacy wastes from R&D on nuclear power and medical isotopes and military activities in the 1940s and early 1950s. The programme covers clean-up of AECL contaminated lands, radioactive wastes and decommissioning old infrastructure which the government is responsible for. A large amount of low-level legacy waste from former radium and uranium refinery operations at Port Hope, Ontario, will be permanently emplaced in an above-ground repository.
Decommissioning
Three power reactors have been shut down and are being decommissioned: Gentilly 1, Douglas Point and Rolphton NPD - all owned by AECL. They were shut down in 1977, 1984 and 1987 respectively and are expected to be demolished in about 30 years. Gentilly 1 was a steam-generating heavy water reactor with vertical pressure tubes, light water coolant and heavy water moderation. It was not successful, and had only about 180 full-power days in six years operation. The other two were prototype Candu designs.
Other fuel cycle activities
Uranium mining in Canada is covered in the information page on Uranium Production in Canada.
Cameco's refinery at Blind River, Ontario takes uranium oxide concentrate (U3O8) from mines in Canada and abroad and refines it to UO3, an intermediate product. The UO3 is trucked to Port Hope, Ontario where Cameco has about one quarter of the Western world's uranium hexafluoride (UF6) conversion capacity – 12,400 tU per year – and provides the only commercial supply of fuel-grade natural (unenriched) uranium dioxide (UO2). The uranium hexafluoride is enriched outside Canada for use in light water reactors, while natural UO2 is used to fabricate fuel bundles for CANDU reactors in Canada and abroad. About 80% of the UO3 from Blind River is converted to UF6, while the remainder is refined to UO2. Two fuel fabrication plants in Ontario process some 1,900 tonnes of uranium per year to UO2 fuel pellets, mainly for domestic CANDU reactors. Between 15 and 20% of Canada's uranium production is consumed domestically.
Safety
The Canadian Nuclear Safety Commission (CNSC) is responsible for regulating and enforcing strict safety standards at domestic nuclear facilities and charged with administering the country's safeguards agreement. It was set up in 2000 under the new Nuclear Safety & Control Act and subsequent regulations as successor to the Atomic Energy Control Board, which had served since 1946. The CNSC reports to parliament through the Minister of Natural Resources.
Non-proliferation
Canada's uranium is sold strictly for electrical power generation only, and international safeguards are in place to ensure this. Nuclear equipment and services are also for peaceful uses only. The CNSC assists the International Atomic Energy Agency (IAEA) by allowing access to Canadian nuclear facilities and arranging for the installation of safeguards equipment at the sites. It reports regularly to the IAEA on nuclear materials held in Canada. The CNSC also manages a program for research and development in support of IAEA safeguards, the Canadian Safeguards Support Programme.
Canada is a party to the Nuclear Non-Proliferation Treaty (NPT) as a non-nuclear weapons state. Its safeguards agreement under the NPT came into force in 1972 and the Additional Protocol in relation to this came into force in 2000. A bilateral safeguards agreement is required with each customer nation as a precondition of trade, placing additional requirements on them beyond those of the NPT and the IAEA. Canada is also a member of the Nuclear Suppliers Group.
Further Information
Appendix 1: Ontario Energy PolicyAppendix 2: Alberta Tar Sands
Related information pages
Uranium Production in Canada
Notes
a. The four Pickering A reactors were laid up in 1997. Pickering A4 was restarted in 2003 and Pickering A1 in 2005. There are no plans to bring Pickering A2 and A3 back into service and these two units are not listed in the Table. Bruce A2 was taken out of service in 1995, A1 followed in 1997, and Bruce A3 and A4 in 1998. Bruce A3 and A4 were restarted in 2004 and 2003, respectively. Bruce A1 and A2 are being refurbished and are due to restart in 2010. While the Table lists Bruce A1 and A2, these units are not included in the total. Bruce B8 achieved a 3% uprate to about 820 MWe in March 2010, the last of the Bruce B units to do so through re-ordering the fuel bundles. The Bruce A units had been done prior to 2001. [Back]
b. Point Lepreau and Gentilly 2 are Candu-6 types (700 MWe class), as are those at Cernavoda, Wolsong and Qinshan. [Back]
c. The Ontario proposals are taken as amounting to 4,000 MWe in total and the first two units at Bruce, plus two units at Darlington, are listed as 'planned' in the WNA reactor table. The other units in the table are categorised as 'proposed'. [Back]
d. South Korea (KAERI) has built a 30 MWt version of MAPLE – Hanaro – which started up in 1995 and is operating successfully. MAPLE had also been shortlisted for Australia's 20 MWt replacement research reactor in 1999. [Back]
References
1. Canadian Energy Research Institute, The Canadian Nuclear Industry: Contributions to the Canadian Economy, Final Report, Prepared for the Canadian Nuclear Association (June 2008) [Back]
2. Smitherman rejects Nanticoke nuclear plant plan, Toronto Star (31 October 2008); Nanticoke a potential nuclear site, World Nuclear News (31 October 2008) [Back]
3. Saskatchewan 2020 - Clean energy. New opportunity. Report on Bruce Power’s Feasibility Study, Bruce Power (November 2008) [Back]
4. Capturing the full potential of the uranium value chain in Saskatchewan, Uranium Development Partnership (31 March 2009) [Back]
5. The Government’s Strategic Direction on Uranium Development, Government of Saskatchewan (December 2009). See also Government of Saskatchewan news release, Government Announces Strategic Direction on Uranium Development (17 December 2009) [Back]
6. AECL halts development of MAPLE project, World Nuclear News (19 May 2008) [Back]
7. Isotope producer is to restart amid controversy, World Nuclear News (12 December 2007); Fallout from isotope crisis hits top regulator, World Nuclear News (16 January 2008) [Back]
8. Implementing Adaptive Phased Management - 2009 to 2013, Nuclear Waste Management Organization (January 2009) [Back]
General sources
The Canadian Nuclear Industry and its Economic Contributions webpage on the Natural Resources Canada website (www.nrcan.gc.ca)The Canadian Nuclear Industry: Contributions to the Canadian Economy, Canadian Energy Research Institute (June 2008)Canadian Nuclear Association (www.cna.ca)